20-F 1 brhc10020710_20f.htm 20-F

UNITED STATES
SECURITIES AND EXCHANGE COMMISSION
Washington, D.C. 20509

Form 20-F

(Mark One)


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


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

For the fiscal year ended December 31, 2020
OR


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


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

Date of event requiring this shell company report__________
For the transition period from_________to_________
Commission file number: 001-36487

Atlantica Sustainable Infrastructure plc

(Exact name of Registrant as specified in its charter)

Not applicable
(Translation of Registrant’s name into English)

England and Wales
(Jurisdiction of incorporation or organization)

Great West House, GW1, 17th floor
Great West Road
Brentford, United Kingdom TW8 9DF
Tel: +44 203 499 0465
(Address of principal executive offices)

Santiago Seage
Great West House, GW1, 17th floor
Great West Road
Brentford, United Kingdom TW8 9DF
Tel: +44 203 499 0465

(Name, Telephone, E-mail and/or Facsimile number and Address of Company Contact Person)

Securities registered or to be registered pursuant to Section 12(b) of the Act.
 
Title of each class
Trading Symbol
 
Name of each exchange on which registered
Ordinary Shares, nominal value $0.10 per share
AY
 
NASDAQ Global Select Market



Securities registered or to be registered pursuant to Section 12(g) of the Act.
 
None
 
Securities for which there is a reporting obligation pursuant to Section 15(d) of the Act.
 
None
Indicate the number of outstanding shares of each of the issuer’s classes of capital or common stock as of the close of the period covered by the annual report: 106,670,862 ordinary shares, nominal value $0.10 per share.
 
Indicate by check mark if the registrant is a well-known seasoned issuer, as defined in Rule 405 of the Securities Act. ☒Yes ☐ No
 
If this report is an annual or transition report, indicate by check mark if the registrant is not required to file reports pursuant to Section 13 or 15(d) of the Securities Exchange Act of 1934. ☐Yes ☒ No
 
Indicate by check mark whether the registrant (1) has filed all reports required to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during the preceding 12 months (or for such shorter period that the registrant was required to file such reports), and (2) has been subject to such filing requirements for the past 90 days. ☒Yes ☐ No
 
Indicate by check mark whether the registrant has submitted electronically every Interactive Data File required to be submitted pursuant to Rule 405 of Regulation S-T (§232.405 of this chapter) during the preceding 12 months (or for such shorter period that the registrant was required to submit such files). ☒Yes ☐ No
 
Indicate by check mark whether the registrant is a large accelerated filer, an accelerated filer, a non-accelerated filer, or an emerging growth company. See definition of “large accelerated filer, “accelerated filer,” and “emerging growth company” in Rule 12b-2 of the Exchange Act.
 
Large accelerated filer ☒
Accelerated filer ☐
Non-accelerated filer ☐
   
Emerging growth company ☐

Indicate by check mark whether the registrant has filed a report on and attestation to its management’s assessment of the effectiveness of its internal control over financial reporting under Section 404(b) of the Sarbanes-Oxley Act (15 U.S.C. 7262(b)) by the registered public accounting firm that prepared or issued its audit report. ☒
 
Indicate by check mark which basis of accounting the registrant has used to prepare the financial statements included in this filing:
 

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

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

ATLANTICA SUSTAINABLE INFRASTRUCTURE PLC
TABLE OF CONTENTS
 
   
Page
6
9
10
ITEM 1.
11
ITEM 2.
11
ITEM 3.
11
B.
11
C.
11
D.
11
ITEM 4.
41
A.
41
B.
43
C.
75
D.
75
ITEM 4A.
75
ITEM 5.
76
A.
76
B.
92
C.
101
D.
101
E.
101
G.
105
ITEM 6.
106
A.
106
B.
109
C.
119
D.
121
E.
121
ITEM 7.
122
A.
122
B.
123
C.
126
ITEM 8.
126
A.
126
B.
128
ITEM 9.
128
A.
128
B.
129
C.
129
D.
129
E.
129
F.
129
ITEM 10.
129
A.
129
B.
129
C.
129
D.
129
E.
129
F.
133
G.
133
H.
133
I.
133
ITEM 11.
134

ITEM 12.
135
A.
135
B.
135
C.
135
D.
136
ITEM 13.
136
ITEM 14.
136
ITEM 15.
136
ITEM 16.
137
ITEM 16A.
137
ITEM 16B.
137
ITEM 16C.
137
ITEM 16D.
139
ITEM 16E.
139
ITEM 16F.
139
ITEM 16G.
139
ITEM 16H.
139
ITEM 17.
139
ITEM 18.
139
ITEM 19.
140

CAUTIONARY STATEMENTS REGARDING FORWARD-LOOKING STATEMENTS
 
This report includes forward-looking statements within the meaning of the Private Securities Litigation Reform Act of 1995. Any statements that express, or involve discussions as to, expectations, beliefs, plans, objectives, assumptions, strategies, future events or performance (often, but not always, through the use of words or phrases such as may result, are expected to, will continue, is anticipated, believe, will, could, should, would, estimated, may, plan, potential, future, projection, goals, target, outlook, predict and intend or words of similar meaning) are not statements of historical facts and may be forward looking. Such statements occur throughout this report and include statements with respect to our expected trends and outlook, potential market and currency fluctuations, occurrence and effects of certain trigger and conversion events, our capital requirements, changes in market price of our shares, future regulatory requirements, the ability to identify and/or consummate future investments and acquisitions on favorable terms, reputational risks, divergence of interests between our company and that of our largest shareholder, tax and insurance implications, and more. Forward-looking statements involve estimates, assumptions and uncertainties. Accordingly, any such statements are qualified in their entirety by reference to, and are accompanied by, important factors included in Part I, Item 3D. Risk Factors (in addition to any assumptions and other factors referred to specifically in connection with such forward-looking statements) that could have a significant impact on our operations and financial results, and could cause our actual results to differ materially from those contained or implied in forward-looking statements made by us or on our behalf in this Form 20-F, in presentations, on our website, in response to questions or otherwise. These forward-looking statements include, but are not limited to, statements relating to:
 

the condition of the debt and equity capital markets and our ability to borrow additional funds and access capital markets, as well as our substantial indebtedness and the possibility that we may incur additional indebtedness going forward;
 

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

government regulation, including compliance with regulatory and permit requirements and changes in tax laws, market rules, rates, tariffs, environmental laws and policies affecting renewable energy;
 

changes in tax laws and regulations;
 

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

our ability to finance and consummate new investments and acquisitions on favorable terms or to close outstanding acquisitions, including PTS;
 

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

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

risks related to our reliance on third-party contractors or suppliers;
 

risks related to our ability to maintain appropriate insurance over our assets;
 

risks related to our exposure in the labor market;
 

potential issues arising with our operators’ employees including disagreement with employees’ unions and subcontractors;
 

risks related to extreme weather events related to climate change could damage our assets or result in significant liabilities and cause an increase in our operation and maintenance costs;
 

the effects of litigation and other legal proceedings (including bankruptcy) against us and our subsidiaries;
 

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

our electricity generation, our projections thereof and factors affecting production, including those related to the COVID-19 outbreak;
 

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

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

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


potential impact of the COVID-19 outbreak on our business, financial condition, results of operations and cash flows;
 

reputational and financial damage caused by our off-taker PG&E and Pemex;
 

sale of electricity to the Mexican market;
 

guidance related to amount of Adjusted EBITDA from low carbon footprint assets and
 

other factors discussed under “Risk Factors”.
 
Any forward-looking statement speaks only as of the date on which such statement is made, and we undertake no obligation to update any forward-looking statement to reflect events or circumstances, including, but not limited to, unanticipated events, after the date on which such statement is made, unless otherwise required by law. New factors emerge from time to time and it is not possible for management to predict all of such factors, nor can it assess the impact of each such factor on the business or the extent to which any factor, or combination of factors, may cause actual results to differ materially from those contained or implied in any forward-looking statement.
 
CURRENCY PRESENTATION AND DEFINITIONS
 
In this annual report, all references to “U.S. dollar,” “$” and “USD” are to the lawful currency of the United States, all references to “euro,” “€” or “EUR” are to the single currency of the participating member states of the European and Monetary Union of the Treaty Establishing the European Community, as amended from time to time and all references to “South African rand,” “R” and “ZAR” are to the lawful currency of the Republic of South Africa.
 
Unless otherwise specified or the context requires otherwise in this annual report:


references to “2019 Notes” refer to the 7.000% Senior Notes due 2019 in an aggregate principal amount of $255 million issued on November 17, 2014, as further described in “Item 5.B—Liquidity and Capital Resources—Financing Arrangements—2019 Notes”;
 

references to “2020 Green Private Placement” refer to the €290 million (approximately $354 million) senior secured notes maturing in June 20, 2026 which were issued under a senior secured note purchase agreement entered with a group of institutional investors as purchasers of the notes issued thereunder as further described in “Item 5.B—Liquidity and Capital Resources—Financing Arrangements—2020 Green Private Placement;
 

references to “AAGES” refer to the joint venture between Algonquin and Abengoa to invest in the development and construction of clean energy and water infrastructure contracted assets;
 

references to “AAGES ROFO Agreement” refer to the agreement we entered into with AAGES on March 5, 2018, which became effective upon completion of the Share Sale, that provides us a right of first offer to purchase any of the AAGES ROFO Assets, as amended and restated from time to time;
 

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;
 

references to “ACS” refer to ACS Group;
 

references to “ACT” refer to the gas-fired cogeneration facility located inside the Nuevo Pemex Gas Processing Facility near the city of Villahermosa in the State of Tabasco, Mexico;
 

references to “Algonquin” refer to, as the context requires, either Algonquin Power & Utilities Corp., a North American diversified generation, transmission and distribution utility, or Algonquin Power & Utilities Corp. together with its subsidiaries;
 

references to “Algonquin ROFO Agreement” refer to the agreement we entered into with Algonquin on March 5, 2018, which became effective upon completion of the Share Sale, under which Algonquin granted us a right of first offer to purchase any of the assets offered for sale located outside of the United States or Canada as amended from time to time. See “Item 7.B—Related Party Transactions—Algonquin drop down agreement and Right of First Offer on assets outside the United States or Canada”;
 

references to “Amherst Island Partnership” or AIP refer to the holding company of Windlectric Inc;
 

references to “Annual Consolidated Financial Statements” refer to the audited annual consolidated financial statements as of December 31, 2020 and 2019 and for the years ended December 31, 2020, 2019 and 2018, including the related notes thereto, prepared in accordance with IFRS as issued by the IASB (as such terms are defined herein), included in this annual report;
 

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

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

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

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

references to “ATS” refer to ABY Transmision Sur S.A.;
 

references to “AYES Canada” refer to Atlantica Sustainable Infrastructure Energy Solutions Canada Inc., a vehicle formed by Atlantica and Algonquin to channel co-investment opportunities;
 

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

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

references to “Calgary District Heating” refer to the district heating asset in Canada, which we agreed to acquire in the fourth quarter of 2020 for a total equity investment of approximately $20 million, subject to conditions precedent and regulatory approvals;
 

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

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

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

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

references to “Coso” refer to the 135 MW geothermal plant located in California, which we agreed to acquire in December 2020, subject to customary conditions.;
 

references to “DOE” refer to the U.S. Department of Energy;
 

references to “DTC” refer to The Depository Trust Company;
 

references to “EMEA” refer to Europe, Middle East and Africa;
 

references to “EPACT” refer to the Energy Policy Act of 2005;
 

references to “EPC” refer to engineering, procurement and construction;
 

references to “EURIBOR” refer to Euro Interbank Offered Rate, a daily reference rate published by the European Money Markets Institute, based on the average interest rates at which Eurozone banks offer to lend unsecured funds to other banks in the euro wholesale money market;
 

references to “EU” refer to the European Union;
 

references to “Exchange Act” refer to the U.S. Securities Exchange Act of 1934, as amended, or any successor statute, and the rules and regulations promulgated by the SEC thereunder;
 

references to “Federal Financing Bank” refer to a U.S. government corporation by that name;
 

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

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

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

references to “Green Project Finance” refer to the green project financing agreement entered into between Logrosan, the sub-holding company of Solaben 1 & 6 and Solaben 2 & 3, as borrower, and ING Bank, B.V. and Banco Santander S.A., as lenders, as further described in “Item 2—Management’s Discussion and Analysis of Financial Condition and Results of Operations—Liquidity and Capital Resources—Sources of Liquidity—Green Project Finance”;
 

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

references to “GWh” refer to gigawatt hour;
 

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

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

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

references to “IRC” refer to the Internal Revenue Code of 1986;
 

references to “ITC” refer to investment tax credits;
 

references to “JIBAR” refer to Johannesburg Interbank Average Rate;
 

references to “La Sierpe” refer to the 20MW solar asset in Colombia to be acquired from Algonquin. by mid-2021, subject to customary conditions;
 

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

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

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

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

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

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

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

references to “MW” refer to megawatts;
 

references to “MWh” refer to megawatt hour;
 

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

references to “NEPA” refer to the National Environment Policy Act;
 

references to “NOL” refer to net operating loss;
 

references to “Note Issuance Facility 2017” refer to the senior secured note facility dated February 10, 2017, of €275 million (approximately $336 million), with Elavon Financial Services DAC, UK Branch, as facility agent and a group of funds managed by Westbourne Capital as purchasers of the notes issued thereunder;
 

references to “Note Issuance Facility 2020” refer to the senior unsecured note facility dated July 8, 2020, of €140 million (approximately $171 million), with Lucid Agency Services Limited, as facility agent and a group of funds managed by Westbourne Capital as purchasers of the notes issued thereunder;
 

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

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

references to “Pemex” refer to Petróleos Mexicanos;
 

references to “PFIC” refer to passive foreign investment company within the meaning of Section 1297 of the IRC;
 

references to “PG&E” refer to PG&E Corporation and its regulated utility subsidiary, Pacific Gas and Electric Company collectively;
 

references to “PPA” refer to the power purchase agreements through which our power generating assets have contracted to sell energy to various off-takers;
 

references to “PTC” refer to production tax credits;
 

references to “PTS” refer to Pemex Transportation System;
 

references to “Registrar” refer to The Bank of New York Mellon;
 

references to “Revolving Credit Facility” refers to the credit and guaranty agreement with a syndicate of banks entered into on May 10, 2018 and amended on January 24, 2019, August 2, 2019, December 17, 2019 and August 28, 2020, providing for a senior secured revolving credit facility in an aggregate principal amount of $425 million;
 

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

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

references to “ROFO agreements” refer to the AAGES ROFO Agreement and Algonquin ROFO Agreement;
 

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

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

references to “Share Sale” refer to the sale by Abengoa to Algonquin of 25% of our ordinary shares pursuant to an agreement for the sale that was entered into in November 2017;
 

references to the “Shareholders’ Agreement” refer to the agreement by and among Algonquin Power & Utilities Corp., Abengoa-Algonquin Global Energy Solutions and Atlantica Sustainable Infrastructure plc, dated March 5, 2018, as amended, which became effective upon completion of the Share Sale;
 

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

references to “Solnova 1, 3 & 4” refer to a 150 MW concentrating solar power facility wholly owned by Atlantica Sustainable Infrastructure, located in the municipality of Sanlucar la Mayor, Spain;
 

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

references to “Tenes” refer to the water desalination plant in Algeria, which is 51% owned by Befesa Agua Tenes;
 

references to “Total-Record Incident” refer to the total number of recordable accidents with and without leave (lost time injury) recorded in the last 12 months per two hundred thousand worked hours;
 

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

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

references to “we,” “us,” “our,” “Atlantica” and the “Company” refer to Atlantica Sustainable Infrastructure plc and its subsidiaries, unless the context otherwise requires.
 
PRESENTATION OF FINANCIAL INFORMATION
 
The financial information as of December 31, 2020 and 2019 and for the years ended December 31, 2020, 2019 and 2018 is derived from, and qualified in its entirety by reference to, our Annual Consolidated Financial Statements, which are included elsewhere in this annual report and prepared in accordance with IFRS as issued by the IASB.
 
Certain numerical figures set out in this annual report, including financial data presented in millions or thousands and percentages describing market shares, have been subject to rounding adjustments, and, as a result, the totals of the data in this annual report may vary slightly from the actual arithmetic totals of such information. Percentages and amounts reflecting changes over time periods relating to financial and other data set forth in “Item 5.A—Operating and Financial Review and Prospects—Operating Results” are calculated using the numerical data in our Annual Consolidated Financial Statements or the tabular presentation of other data (subject to rounding) contained in this annual report, as applicable, and not using the numerical data in the narrative description thereof.
 
Non-GAAP Financial Measures
 
This annual report contains non-GAAP financial measures including Adjusted EBITDA.
 
Adjusted EBITDA is calculated as profit/(loss) for the year attributable to the parent company, after adding back loss/(profit) attributable to non-controlling interest from continued operations, income tax, share of profit/(loss) of associates carried under the equity method, finance expense net, depreciation, amortization and impairment charges of entities included in the Annual Consolidated Financial Statements.

Until December 31, 2019, we reported Further Adjusted EBITDA as one of our key metrics. Further 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 from continued operations, income tax, share of profit/(loss) of associates carried under the equity method, finance expense net, depreciation, amortization and impairment charges of entities included in the Annual Consolidated Financial Statements and dividends received from our preferred equity investment in ACBH until 2017. We no longer report Further Adjusted EBITDA because the Company has not received dividends from our preferred equity investment in ACBH during the period under review or in any of the comparable periods. ACBH was Abengoa Concessões Brasil Holding, a subsidiary holding company of Abengoa that was engaged in the development, construction, investment and management of concessions in Brazil, comprised mostly of transmission lines and which is currently undergoing a restructuring process in Brazil.

Our management believes Adjusted EBITDA is useful to investors and other users of our financial statements in evaluating our operating performance because it provides them with an additional tool to compare business performance across companies and across periods. This measure is widely used by investors to measure a company’s operating performance without regard to items such as interest expense, taxes, depreciation and amortization, which can vary substantially from company to company depending upon accounting methods and book value of assets, capital structure and the method by which assets were acquired. This measure is widely used by other companies in our industry.
 
Our management uses Adjusted EBITDA as a measure of operating performance to assist in comparing performance from period to period on a consistent basis and to readily view operating trends, as a measure for planning and forecasting overall expectations and for evaluating actual results against such expectations, and in communications with our Board of Directors, shareholders, creditors, analysts and investors concerning our financial performance.
 
We present non-GAAP financial measures because we believe that they and other similar measures are widely used by certain investors, securities analysts and other interested parties as supplemental measures of performance and liquidity. The non-GAAP financial measures may not be comparable to other similarly titled measures of other companies and have limitations as analytical tools and should not be considered in isolation or as a substitute for analysis of our operating results as reported under IFRS as issued by the IASB. Non-GAAP financial measures and ratios are not measurements of our performance or liquidity under IFRS as issued by the IASB and should not be considered as alternatives to operating profit or profit for the year or any other performance measures derived in accordance with IFRS as issued by the IASB or any other generally accepted accounting principles or as alternatives to cash flow from operating, investing or financing activities.

Some of the limitations of these non-GAAP measures are:
 

they do not reflect our cash expenditures or future requirements for capital expenditures or contractual commitments;
 

they do not reflect changes in, or cash requirements for, our working capital needs;
 

they may not reflect the significant interest expense, or the cash requirements necessary, to service interest or principal payments, on our debts;
 

although depreciation and amortization are non-cash charges, the assets being depreciated and amortized will often need to be replaced in the future and Adjusted EBITDA does not reflect any cash requirements that would be required for such replacements; and
 

the fact that other companies in our industry may calculate Adjusted EBITDA differently than we do, which limits their usefulness as comparative measures.
 
PRESENTATION OF INDUSTRY AND MARKET DATA
 
In this annual report, we rely on, and refer to, information regarding our business and the markets in which we operate and compete. The market data and certain economic and industry data and forecasts used in this annual report were obtained from internal surveys, market research, governmental and other publicly available information, independent industry publications and reports prepared by industry consultants. We believe that these industry publications, surveys and forecasts are reliable, but we have not independently verified them, and there can be no assurance as to the accuracy or completeness of the included information.
 
Certain market information and other statements presented herein regarding our position relative to our competitors are not based on published statistical data or information obtained from independent third parties but reflect our best estimates. We have based these estimates upon information obtained from our customers, trade and business organizations and associations and other contacts in the industries in which we operate.
 
Elsewhere in this annual report, statements regarding our contracted assets and concessions activities, our position in the industries and geographies in which we operate are based solely on our experience, our internal studies and estimates and our own investigation of market conditions.
 
All of the information set forth in this annual report relating to the operations, financial results or market share of our competitors has been obtained from information made available to the public in such companies’ publicly available reports and independent research, as well as from our experience, internal studies, estimates and investigation of market conditions. We have not funded, nor are we affiliated with, any of the sources cited in this annual report. We have not independently verified the information and cannot guarantee its accuracy.
 
All third-party information, as outlined above, has to our knowledge been accurately reproduced and, as far as we are aware and are able to ascertain, no facts have been omitted which would render the reproduced information inaccurate or misleading, but there can be no assurance as to the accuracy or completeness of the included information.
 
PART I
 
ITEM 1.
IDENTITY OF DIRECTORS, SENIOR MANAGEMENT AND ADVISERS

Not applicable.
 
ITEM 2.
OFFER STATISTICS AND EXPECTED TIMETABLE

Not applicable.
 
ITEM 3
KEY INFORMATION

B.
Capitalization and Indebtedness

Not applicable.

C.
Reasons for the Offer and Use of Proceeds

Not applicable.
 
D.
Risk Factors
 
Investing in our securities involves a high degree of risk. You should carefully consider the risks and uncertainties described below, together with the other information contained in this annual report, including our Annual Consolidated Financial Statements and related notes, included elsewhere in this annual report, before making any investment decision. The risks described below may not be the only risks we face. We have described only those risks that we currently consider to be material and there may be additional risks that we do not currently consider to be material or of which we are not currently aware. Any of the following risks and uncertainties could have a material adverse effect on our business, prospects, results of operations and financial condition. The market price of our securities could decline due to any of these risks and uncertainties, and you could lose all or part of your investment.
 
Risk Factor Summary

Set forth below is only a summary of the principal risks associated with an investment in our shares:

Risks Related to Our Business and Our Assets

Our failure to maintain safe work environments may expose us to significant financial losses, as well as civil and criminal liabilities.
Our off-takers may not fulfill their obligations and, as our off-take agreements expire, we may not be able to replace them with agreements on similar terms in light of increasing competition in the markets in which we operate.
The concession agreements or power purchase agreements under which we conduct some of our operations are subject to revocation, termination or tariff reduction.
The performance of our assets under our PPAs or concession contracts may be adversely affected by problems, mainly including those related to our reliance on third-party contractors and suppliers.
Supplier concentration may expose us to significant financial credit or performance risk.
Certain of our facilities may not perform as expected.
Maintenance, expansion and refurbishment of our electric generation and other facilities involve significant risks that could result in unplanned power outages or reduced output or availability.
Our business may be adversely affected by an increased number of extreme and chronic weather events related to climate change.
The generation of electric energy from renewable energy sources depends heavily on suitable meteorological conditions, and if solar or wind conditions are unfavorable, our electricity generation, and therefore revenue from our renewable energy generation facilities using our systems, may be substantially below our expectations.
Our business may be adversely affected by catastrophes, natural disasters, unexpected geological or other physical conditions, or criminal or terrorist acts at one or more of our plants, facilities and electric transmission lines.
 
Risks Related to the COVID-19 Pandemic

The outbreak of COVID-19 could have a material adverse impact on our business, financial condition, liquidity, results of operations, cash flows, cash available for distribution and ability to make cash distributions to our shareholders.
 
Risks Related to Our Relationship with Algonquin and Abengoa

Algonquin is our largest shareholder and exercises substantial influence over us.
Our ownership structure and certain service agreements may create significant conflicts of interest that may be resolved in a manner that is not in our best interests.
If Abengoa defaults on certain of its debt obligations, including as a result of the recent insolvency filing by their holding company Abengoa S.A., we could potentially be in default of certain of our project financing agreements.
Abengoa’s financial condition, including the insolvency filing of Abengoa, S.A., could affect its ability to satisfy its obligations with us under different agreements, including operation and maintenance agreements as well as indemnities and other contracts in place, and may affect our reputation.
Abengoa S.A. (the holding company) has filed for insolvency and it or any of its subsidiaries may be forced to file for bankruptcy under the Spanish Insolvency Act and, as a result, it may be subject to insolvency claw-back actions, which may have a material adverse effect on our business, financial condition, results of operations and cash flows.
 
Risks Related to Our Indebtedness

Our indebtedness could limit our ability to react to changes in the economy or our industry, expose us to the risk of increased interest rates and limit our activities due to covenants in existing financing agreements. It could also adversely affect our ability to make distributions from the project subsidiaries to Atlantica, and our ability to fund operations, pay dividends or raise additional capital.

We may be unable to refinance or replace our existing indebtedness or repay our existing debt as it becomes due.
We may not be able to arrange the required or desired financing for acquisitions and for the successful refinancing of the Company’s project level and corporate level indebtedness.
We may be subject to increased finance expenses if we do not effectively manage our exposure to interest rate and foreign currency exchange rate risks.
Potential future defaults by our subsidiaries, our off-takers, our suppliers, Abengoa or other persons could adversely affect us.
Uncertainty relating to the LIBOR calculation process and potential phasing out of LIBOR in the future may adversely affect the value of any outstanding debt instruments.
A change of control or a delisting of our shares may have negative implications for us.
 
Risks Related to Our Growth Strategy

We may not be able to identify or consummate future investments and acquisitions on favorable terms, or at all.
In order to grow our business, we may invest in or acquire assets or businesses which have a higher risk profile or are less ESG-friendly than certain assets in our current portfolio.
We cannot guarantee the success of our recent and future acquisitions.
Our cash dividend policy may limit our ability to grow and make acquisitions through cash on hand.
 
Risks Related to the Markets in Which We Operate

Difficult conditions in the global economy and in the global capital markets have caused, and may continue to cause, a sharp reduction in worldwide demand for our products and services
We have international operations and investments, including in emerging markets that could be subject to economic, social and political uncertainties.
We are exposed to political, social and macroeconomic risks relating to the United Kingdom’s exit from the European Union.
 
Risks Related to Regulation
 
We are subject to extensive governmental regulation in a number of different jurisdictions, and our inability to comply with existing regulations or requirements or changes in applicable regulations or requirements may have a negative impact on our business, financial condition, results of operations and cash flows.
Our business is subject to stringent environmental regulation.
Government regulations could change at any time and such changes may negatively impact our current business and our growth strategy.
Revenues in certain of our assets are mainly defined by regulation and some of the parameters defining the remuneration are subject to review.
Our international operations require us to comply with anti-corruption and other laws and regulations of the United States government and various non-U.S. jurisdictions.
 
Risks Related to Ownership of Our Shares

We may not be able to pay a specific or increasing level of cash dividends to holders of our shares in the future.
Future sales of our shares by Algonquin or its lenders or by other substantial shareholders may cause the price of our shares to fall.
 
Risks Related to Taxation

Changes in our tax position can significantly affect our reported earnings and cash flows.
Our future tax liability may be greater than expected if we do not use sufficient NOLs to offset our taxable income.
Our ability to use U.S. NOLs to offset future income may be limited.
Distributions to U.S. Holders of our shares may be fully taxable as dividends.
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.
 

I.
Risks Related to Our Business and Our Assets
 
Our failure to maintain safe work environments may expose us to significant financial losses, as well as civil and criminal liabilities.
 
The facilities we operate often put our employees and others, including those of our subcontractors, in close proximity with large pieces of mechanized equipment, moving vehicles, manufacturing or industrial processes, heat or liquids stored under pressure and highly regulated materials. On most projects and at most facilities, we, together in some cases with the operation and maintenance supplier, are responsible for safety. Accordingly, we must implement safe practices and safety procedures, which are also applicable to on-site subcontractors. If we or the operation and maintenance supplier fail to design and implement such practices and procedures or if the practices and procedures are ineffective or if our operation and maintenance service providers or other suppliers do not follow them, our employees and others may become injured, and we may incur civil or criminal liabilities. Unsafe work sites also have the potential to increase employee turnover, increase the cost of a project to our customers or the operation of a facility, and raise our operating costs. Any of the foregoing could result in reputational damage and/or financial losses, which could have a material adverse effect on our business, financial condition, results of operations and cash flows.
 
In addition, our projects and the operation of our facilities can involve the handling of hazardous and other highly regulated materials, which, if improperly handled or disposed of, could subject us or our suppliers to civil and criminal liabilities. We are also subject to regulations dealing with occupational health and safety. Although we maintain divisions whose primary purpose is to ensure we implement effective health, safety and environmental work procedures throughout our organization, the failure to comply with such regulations could subject us to reputational damage and/or liability. In addition, we may incur liability based on allegations of illness or disease resulting from exposure of employees or other persons to hazardous materials or equipment that we handle or are present in our workplaces.
 
Counterparties to our off-take agreements may not fulfill their obligations and, as our contracts expire, we may not be able to replace them with agreements on similar terms in light of increasing competition in the markets in which we operate.
 
A significant portion of the electric power we generate, the transmission capacity we have, and our desalination capacity is sold under long-term off-take agreements with public utilities, industrial or commercial end-users or governmental entities, with a weighted average remaining duration of approximately 17 years as of December 31, 2020.
 
If, for any reason, including, but not limited to, a deterioration in their financial situation or bankruptcy, any of our clients are unable or unwilling to fulfill their related contractual obligations or if they refuse to accept delivery of power delivered thereunder or if they otherwise terminate such agreements prior to the expiration thereof, or if prices were re-negotiated under a bankruptcy situation, or if they delayed payments, our assets, liabilities, business, financial condition, results of operations and cash flow may be materially adversely affected. Furthermore, to the extent any of our power, transmission capacity or desalination capacity purchasers are, or are controlled by, governmental entities, our facilities may be subject to sovereign risk or legislative or other political action that may hamper their contractual performance.
 
On January 29, 2019, PG&E, the off-taker for Atlantica with respect to the Mojave plant, filed for reorganization under Chapter 11 of the Bankruptcy Code in the U.S. Bankruptcy Court for the Northern District of California. PG&E paid all invoices corresponding to the electricity delivered after January 28, 2019. Since PG&E failed to assume the PPA within 180 days from the commencement of PG&E’s Chapter 11 proceeding, a technical event of default was triggered under our Mojave project finance agreement in July 2019. On July 1, 2020, PG&E emerged from Chapter 11 and in accordance with the plan of reorganization, assumed the Mojave PPA and paid to Mojave the portion of the invoice corresponding to the electricity delivered for the period between January 1 and January 28, 2019. This invoice was overdue because the services related to the prepetition period and any payment therefore required the approval by the Bankruptcy Court. Therefore, the technical event of default under our Mojave project finance agreement, which was preventing cash distributions from Mojave to Atlantica, was cured and we can make distributions from Mojave.
 
The credit rating of Eskom has weakened and is currently CCC+ from S&P Global Rating (“S&P”), Caa1 from Moody’s Investor Service Inc. (“Moody’s”) and B from Fitch Ratings Inc. (“Fitch”). Eskom is the off-taker of our Kaxu solar plant, a state-owned, limited liability company, wholly owned by the government of the Republic of South Africa. Eskom’s payment guarantees to our Kaxu solar plant are underwritten by the South African Department of Energy, under the terms of an implementation agreement. The credit ratings of the Republic of South Africa have also weakened and as of the date of this report are BB/Ba2/BB- by S&P, Moody’s and Fitch, respectively.
 
In addition, Pemex’s credit rating has also weakened and is currently BBB from S&P, Ba2 from Moody’s and BB- from Fitch. We have been experiencing significant delays from Pemex in collections since the second half of 2019.
 
The cost of renewable energy has considerably decreased over the past years, becoming a consistently competitive source of power generation compared to traditional fossil fuels in many regions, and it is expected to continue falling in the future. In addition, there has been an increase in the number of players and competition in the renewable energy space in the last few years, industrial companies and other independent power producers as well as large infrastructure funds and other financial players. The reduction in the cost of renewable energy and the intense competition has contributed to a reduction in electricity prices paid by the off-takers. In light of these market conditions, our off-takers may try to renegotiate or terminate our PPAs, most of which were signed several years ago and may be more expensive than recent PPAs or than current market prices. In addition, we may not be able to replace an expiring or terminated agreement with an agreement on equivalent terms and conditions, including at prices that permit operation of the related facility on a profitable basis. In addition, we believe that many of our competitors have well-established relationships with our current and potential suppliers, lenders and customers and have extensive knowledge of our target markets. As a result, these competitors may be able to respond more quickly to evolving industry standards and changing customer requirements than us. Adoption of technology more advanced than our own could reduce the power production costs of our competitors, resulting in their having a lower cost structure than is achievable with the technologies we currently employ and adversely affect our ability to compete for off-take agreement renewals. If we are unable to replace an expiring or terminated off-take agreement, the affected facility may temporarily or permanently cease operations.
 
Our inability to enter into new or replacement off-take agreements or to compete successfully against current and future competitors in the markets in which we operate may have a material adverse effect on our business, financial condition, results of operations and cash flows.
 
The concession agreements or power purchase agreements under which we conduct some of our operations are subject to revocation, termination or tariff reduction.
 
Certain of our operations are conducted pursuant to contracts and concessions granted by various governmental bodies and others are pursuant to power purchase agreements signed with governmental entities and private clients. Generally, these contracts and concessions give us rights to provide services for a limited period, subject to various governmental regulations. The governmental bodies or private clients responsible for regulating and monitoring these services often have broad powers to monitor our compliance with the applicable concession and power purchase contracts and can require us to supply them with technical, administrative and financial information. Among other obligations, we may be required to comply with operating targets and efficiency and safety standards established in the concession. Such commitments and standards may be amended in certain cases by the governmental bodies. Our failure to comply with the concession agreements and power purchase agreements or other regulatory requirements may result in contracts and concessions being revoked, not being granted, upheld or renewed in our favor, or, if granted, upheld or renewed, may not be done on as favorable terms as currently applicable. In addition, in some cases our off-takers have an option to acquire the asset or to terminate the concession agreement in exchange for a compensation. All the above could have a material adverse effect on our business, financial condition, results of operations and cash flows.
 
In addition, in some cases, if we fail to comply with certain pre-established conditions, the government or customer (as applicable) may reduce the tariffs or rates payable to us. In addition, during the life of a concession, the relevant government authority may in some cases unilaterally impose additional restrictions on our tariff rates, subject to the regulatory frameworks applicable in each jurisdiction. In some cases, governments may also postpone annual tariff increases until a new tariff structure is approved without compensating us for lost revenue. Furthermore, changes in laws and regulations may, in certain cases, have retroactive effect and expose us to additional compliance costs or interfere with our existing financial and business planning.
 
The performance of our assets under our PPAs or concession contracts may be adversely affected by problems including those related to our reliance on third-party contractors and suppliers.
 
Our projects rely on the supply of services, equipment, including technologically complex equipment and software which we subcontract in some cases to third-party suppliers in order to meet our contractual obligations under our concessions. In circumstances where key components of our equipment, including but not limited to turbines, water pumps, heat exchangers, transformers or electrical generators fail because of design failures or faulty operation or for any other reason, we rely on third parties to continue operating our assets. Equipment may not last as long as expected and we may need to replace it earlier than planned. Damages to our equipment may not be covered by insurance in place. In some cases, the replacement of damaged equipment can take a long period of time, which can cause our plants to curtail or cease operations during such time, which could have a negative impact on our business, financial condition, results of operations and cash flows.
 
For example, Solana and Kaxu have experienced technical issues in their storage systems. Repairs have been carried out in both assets. In Solana, availability in the storage system was lower than expected in 2020 due to certain leaks identified in the storage system in the first quarter of 2020. Improvements and equipment replacements are required over time, have impacted production in 2020 and will continue to impact production in 2021, with the exact scope and timing of repairs subject to review. Solana has a cash repair reserve account funded with approximately $54 million that we expect to use partially or totally for this purpose. However, we cannot guarantee that the repairs will be effective or that additional repairs will not be required. Similar interruptions could happen again at our plants due to failures in key equipment. Design failures, technical inspections by suppliers or the need to replace key equipment can require unexpected capital expenditures and/or outages in our plants, which may have a material adverse effect on our business, financial condition, results of operations and cash flows.
 
In addition, the delivery of products or services which are not in compliance with the requirements of the subcontract, or the late supply of products and services, can cause us to be in default under our contracts with our concession counterparties. To the extent we are not able to transfer all of the risk or be fully indemnified by third-party contractors and suppliers, we may be subject to a claim by our customers as a result of a problem caused by a third party that could have a material adverse effect on our reputation, business, results of operations, financial condition and cash flows.
 
Supplier concentration may expose us to significant financial credit or performance risk.
 
We often rely on a single contracted supplier or a small number of suppliers for the provision of certain personnel, spare parts, equipment, technology, fuel, transportation of fuel, and/or other services required for the operation of certain of our facilities. If any of these suppliers, including Abengoa, Siemens, GE, Rioglass or Nordex, cannot or will not perform under their operation and maintenance and other agreements with us, or satisfy their related warranty obligations, including as a result of insolvency or bankruptcy, we will need to access the marketplace to provide or repair these products and services. There can be no assurance that the marketplace can provide these products and services as, when and where required. We may not be able to enter into replacement agreements on favorable terms or at all. If we are unable to enter into replacement agreements to provide for equipment, technology or fuel and other required services, we may be required to seek to purchase the related goods or services at higher prices. We may also be required to make significant capital contributions to remove, replace or redesign equipment that cannot be supported or maintained by replacement suppliers, which may have a material adverse effect on our credit support terms, business, financial condition, results of operations, and cash flows.
 
The failure of any supplier or customer to fulfill its contractual obligations to us may have a material adverse effect on our business, financial condition, results of operations and cash flows. Consequently, the financial performance of our facilities is dependent on the credit quality of, and continued performance by, our suppliers and vendors.
 
Certain of our facilities may not perform as expected.
 
Our expectations regarding the operating performance of certain assets in our portfolio, particularly Solana and Kaxu, assets recently acquired such as Chile PV 2, Chile PV 1, Tenes and assets for which acquisition has recently been announced and closing is still pending such as Calgary District Heating, La Sierpe and Coso, are based on assumptions, estimates and past experience, and without the benefit of a substantial operating history under our control. Our projections regarding our ability to generate cash available for distribution assumes facilities perform in accordance to our expectations. However, the ability of these facilities to meet our performance expectations is subject to the risks inherent in power generation facilities and the construction of such facilities, including, but not limited to, degradation of equipment in excess of our expectations, system failures and outages. The failure of these facilities to perform as we expect may have a material adverse effect on our business, financial condition, results of operations and cash flows.
 
Maintenance, expansion and refurbishment of electric generation and other facilities involve significant risks that could result in unplanned power outages or reduced output or availability.
 
The facilities in our portfolio may require periodic upgrading and improvement in the future. Any unexpected operational or mechanical failure, including failure associated with breakdowns and forced outages, could reduce the performance and availability of our facilities below expected levels, reducing our revenues. Degradation of the performance of our solar facilities above levels provided for in the related off-take agreements may also reduce its revenues. Unanticipated capital expenditures associated with maintaining, upgrading or repairing our facilities may also reduce profitability.
 
If we make any major modifications to our efficient natural gas or renewable power generation facilities or electric transmission lines, we may be required to comply with more stringent environmental regulations, which would likely result in substantial additional capital expenditures. We may also choose to repower, refurbish or upgrade our facilities based on our assessment that such activity will provide adequate financial returns. Such facilities require time for development and capital expenditures before commencement of commercial operations, and key assumptions underpinning a decision to make such an investment may prove incorrect, including assumptions regarding construction costs, timing, available financing and future fuel and power prices. This may have a material adverse effect on our business, financial condition, results of operations and cash flows.
 
Our business may be adversely affected by an increased number of extreme and chronic weather events related to climate change.
 
Climate change is causing an increasing number of severe and extreme weather events which are a risk to our facilities, including days of extremely high temperatures, severe winds and rains, hurricanes, droughts, fires, cyclones, hail and floods, among others. These risks include:
 

Rising temperatures are also increasing the frequency and intensity of droughts and risk of fire. For example, in California, the size and ferocity of fires has increased significantly in the past 20 years, which have also been very hot and dry years. California wildfires have been especially catastrophic, causing human fatalities and significant material losses. Our transmission lines, including transmission lines and substations which are part of our solar assets, could cause fires. Therefore, they could create significant liabilities if the fire damaged third parties.
 

Severe floods could damage our plants, especially our transmission lines or our generation assets. If an unexpected flood runs close to an existing transmission tower it could cause the fall of one or more transmission towers. Similarly, floods can damage the solar field in our solar plants.
 

Severe winds could cause damage in the solar fields at our solar assets. In 2016, the solar field of Solana was damaged by a wind micro-burst and similar events could happen in the future in our assets.
 

Severe droughts could result in water restrictions or in a deterioration to the properties of water. Droughts may affect the cooling capacity of our power projects. A deterioration of the quality of the water would have an impact on chemical costs in our water treatment plants within our generation facilities.
 

Changes in temperature extremes could also affect the water quality in desalination plants, causing an increase of the chemical products consumption and generating a risk of growth of algae and mollusks within the facilities.
 

Storms with intense lightning activity could damage our plants, especially our wind assets. Our wind farms in Uruguay have already experienced some damage in the past and our assets could be affected again.
 
Furthermore, components of our system, such as structures, mirrors, absorber tubes, blades, PV panels or transformers are susceptible to being damaged by severe weather, including for example by hail or lightning. In addition, replacement and spare parts for key components may be difficult or costly to acquire or may be unavailable and may have long lead times.
 
In addition, our business may be adversely affected by rising mean temperatures caused by climate change. Rising temperatures could cause an increase in our operation and maintenance costs. Rising temperatures are associated to the reduction of the cycle efficiency of our turbines. A temperature rise above a certain threshold would also reduce the efficiency of our solar photovoltaic modules. When the temperature of the solar panel increases, its output current slightly increases while the voltage output is reduced on a linear basis, and therefore panel power production decreases. Likewise, a temperature rise would also have an impact in our wind facilities. Wind energy component is dependent on the air density among other factors. Our desalination plants could also be affected by a temperature increase that would imply higher consumption of chemicals used for operational purposes.
 
If any of these events were to occur at any of our plants, facilities or electric transmission lines, we may not be able to carry out our business activities at that location or such operations could be significantly reduced. Any of these circumstances could result in lost revenue at these sites during the period of disruption and costly remediation, which could have a material adverse effect on our business, financial condition, results of operations and cash flows.
 
The generation of electric energy from renewable energy sources depends heavily on suitable meteorological conditions, and if solar or wind conditions are unfavorable, our electricity generation, and therefore revenue from our renewable energy generation facilities using our systems, may be substantially below our expectations.
 
The electricity produced, and revenues generated by a renewable energy generation facility are highly dependent on suitable solar or wind conditions, as applicable, and associated weather conditions, which are beyond our control.
 
Unfavorable weather and atmospheric conditions could impair the effectiveness of our assets or reduce their output beneath their rated capacity or require shutdown of key equipment, hampering operation of our renewable assets and our ability to achieve forecasted revenues and cash flows.
 
We base our investment decisions with respect to each renewable generation facility on the findings of related wind and solar studies conducted on-site by third parties prior to construction or based on historical conditions at existing facilities. However, actual climatic conditions at a facility site, particularly wind conditions, which are sometimes severe, may not conform to the findings of these studies and therefore, our solar and wind energy facilities may not meet anticipated production levels or the rated capacity of its generation assets, which may have a material adverse effect on our business, financial condition, results of operations and cash flows.
 
In addition, in the case of Coso, the electricity produced, and revenues generated are dependent on the geothermal resource available. In December 2020 we reached an agreement to acquire Coso and closing is expected in the first half of 2021, subject to conditions precedent and regulatory approvals. Our investment decision was made based on the geothermal resource assessed and estimated by a geologist. Geothermal resource may not meet our expectations, which may have a material adverse effect on our business, financial condition, results of operations and cash flows.
 
Our business may be adversely affected by catastrophes, natural disasters, unexpected geological or other physical conditions, or criminal or terrorist acts at one or more of our plants, facilities and electric transmission lines.
 
If one or more of our plants, facilities or electric transmission lines were to be subject in the future to fire, flood, extreme weather conditions (including severe wind), earthquakes or other natural disaster, adverse weather conditions, drought, terrorism, power loss or other catastrophe, or if unexpected geological or other adverse physical conditions (including earthquakes) were to occur at any of our plants, facilities or electric transmission lines, we may not be able to carry out our business activities at that location or such operations could be significantly reduced. We own two assets in Southern California, which is an area classified as high seismic risk. Any of these circumstances could result in lost revenue at these sites during the period of disruption and costly remediation, which could have a material adverse effect on our business, financial condition, results of operations and cash flows. In addition, it is possible that our sites and assets could be affected by criminal or terrorist acts. There are also certain risks for which we may not be able to acquire adequate insurance coverage, including earthquakes. Any such events could have a material adverse effect on our business, financial condition, results of operations and cash flows.
 
Our insurance may be insufficient to cover relevant risks or the cost of our insurance may increase.
 
We cannot guarantee that our insurance coverage is, or will be, sufficient to cover all the possible losses we may face in the future. Our property damage and business interruption policy have significant deductibles and exclusions with respect to some key equipment which, if damaged, could result in financial losses and business interruptions. Moreover, insurance market terms and conditions have been becoming more and more onerous over the last few years and insurance companies are requiring some companies in our sector to retain a portion of the overall risks instead of transferring 100% of those risks to the insurers. As a result, we have self-retained a portion of our own risks and may need to increase this percentage in the future. If equipment failed in one of our assets and this equipment was part of the insurance exclusions or if the event was part of the risks that we have retained, we would need to assume the repairs and business interruption costs, which may have a material adverse effect on our business, financial condition, results of operations and cash flows.
 
Furthermore, in some of our project finance arrangements and PPAs include specific conditions regarding insurance coverage that we may need to modify. If we did not obtain a waiver from our project finance lenders accepting these modifications, an event of default could be triggered by our lenders due to non-compliance with the terms of the project finance agreement. If we were to incur a serious uninsured loss or a loss that significantly exceeded the coverage limits established in our insurance policies or we were not able to modify coverage conditions, this could have a material adverse effect on our business, financial condition, results of operations and cash flows. In addition, our insurance policies are subject to periodic renewals and the terms of the renewal are reviewed by our counterparties. If we were unable to renew our insurance, we would not be in compliance with the requirements of our project finance agreements and our PPAs, which could have a material adverse effect on our business, financial condition, results of operations and cash flows. If insurance premiums were to increase in the future and/or if certain types of insurance coverage were to become unavailable or there was a further increase in deductibles for damages and/or loss of production, it could have a material adverse effect on our business, financial condition, results of operations and cash flows.
 
Also, our insurance policies are subject to review by our counterparties. We may not be able to renew our insurance policies in the terms required by our power purchase agreements and project financing agreements, which could require a waiver from those parties. If insurance premiums were to increase in the future, if certain types of insurance coverage were to become unavailable or there was an increase in deductibles for damages and/or loss of production, it could have a material adverse effect on our ability to comply with our obligations to off-takers and lenders in our project finance agreements. In addition, we might not be able to maintain insurance coverage comparable to those that are currently in effect at comparable cost, or at all. If we were unable to pass any increase in insurance premiums on to our customers, such additional costs could have a material adverse effect on our business, financial condition, results of operations and cash flows.
 
We may have joint venture partners or other co-investors with whom we have material disagreements.
 
We have made and may continue to make equity investments in certain strategic assets managed by or together with third parties, including governmental entities and private entities. In certain cases, we may only have partial or joint control over a particular asset. We hold a minority stake in Honaine (Algeria), Monterrey (Mexico), Amherst (Canada) and Ten West Link (United States) and do not have control over the operation of these assets. In addition, we have partners in Seville PV, Solacor 1 & 2, Solaben 2 & 3, Skikda, Kaxu, Tenes, Chile PV 1 and Chile PV 2. Investments in assets over which we have no, partial or joint control are subject to the risk that the other shareholders of the assets, who may have different business or investment strategies than us or with whom we may have a disagreement or dispute, may have the ability to independently make or block business, financial or management decisions, such as appoint members of management, which may be crucial to the success of the project or our investment in the project, or otherwise implement initiatives which may be contrary to our interests. Additionally, the approval of other shareholders or partners may be required to sell, pledge, transfer, assign or otherwise convey our interest in such assets. Alternatively, other shareholders may have rights of first refusal or rights of first offer in the event of a proposed sale or transfer of our interests in such assets or in the event we acquire an interest in new assets pursuant to ROFO agreements with third parties. These restrictions may limit the price or interest level for our interests in such assets, in the event we want to sell such interests.
 
Finally, our partners in existing or future projects may be unable, or unwilling, to fulfill their obligations under the relevant shareholder agreements, may experience financial or other difficulties or might sell their position to third parties that we did not choose, which may adversely affect our investment in a particular joint venture or adversely affect us. In certain of our joint ventures, we may also rely on the expertise of our partners and, as a result, any failure to perform its obligations in a diligent manner could also adversely affect the joint venture. If any of the foregoing were to occur, our business, financial condition, results of operations and cash flows may be materially adversely affected.
 
The operation and maintenance of most of our assets is labor intensive, and therefore work stoppages by employees could harm our business.
 
The operation and maintenance of most of our assets is labor intensive and our operators’ employees and some of our employees in assets where we perform the operation and maintenance services are covered by collective bargaining agreements. A dispute with a union or employees represented by a union could result in production interruptions caused by work stoppages. In addition, we subcontract the operation and maintenance services in some of our assets. Abengoa is the operation and maintenance supplier in most of the assets for which we subcontract operation and maintenance services and Abengoa’s financial situation, including their recent insolvency filing, could cause a higher risk of dispute with their employees. If our operators’ employees were to initiate a work stoppage, they may not be able to reach an agreement with them as fast as in the case where we were negotiation with our own employees. If a strike or work stoppage or disruption were to occur, our business, financial conditions, results of operations and cash flows may be materially adversely affected.
 
Revenue from our renewable energy and efficient natural gas facilities is or may be partially exposed to market electricity prices.
 
Revenue and operating costs from certain of our existing or future projects depend to some extent on market prices for sale of electricity. Market prices may be volatile and are affected by various factors, including the cost of raw materials, user demand, and if applicable, the price of greenhouse gas emission rights. In several of the jurisdictions in which we operate, we are exposed to remuneration schemes which contain both regulated incentive and market price components. In such jurisdictions, the regulated incentive component may not compensate for fluctuations in the market price component, and, consequently, total remuneration may be volatile. There can be no assurance that market prices will remain at levels which enable us to maintain profit margins and desired rates of return on investment. A decline in market prices below anticipated levels could have a material adverse effect on our business, financial condition, results of operations and cash flows.
 
Lack of electric transmission capacity availability, potential upgrade costs to the electric transmission grid, and other systems constraints could significantly impact our ability to generate electricity power sales and develop new projects.
 
We depend on electric interconnection and transmission facilities owned and operated by others to deliver the wholesale power we sell from our electric generation assets to our customers. A failure or delay in the operation or development of these interconnection or transmission facilities or a significant increase in the cost of the development of such facilities could result in the loss of revenues. Such failures or delays could limit the amount of power our operating facilities deliver or delay the completion of our construction projects, as the case may be. Additionally, such failures, delays or increased costs may have a material adverse effect on our business, financial condition, results of operations and cash flows. If a region’s electric transmission infrastructure is inadequate, our ability to generate electricity may be limited. If restrictive transmission price regulation is imposed, the transmission companies may not have a sufficient incentive to invest in expansion of transmission infrastructure. We cannot predict whether interconnection and transmission facilities will be expanded in specific markets to accommodate competitive access to those markets. Certain of our operating facilities’ generation of electricity may be curtailed without compensation due to transmission limitations or limitations on the electricity grid’s ability to accommodate intermittent electricity generating sources, reducing our revenues and impairing our ability to fully capitalize on a particular facility’s generating potential. Such curtailments may have a material adverse effect on our business, financial condition, results of operations and cash flows.
 
We use information technology and communications systems to run our business, the failure of which could significantly impact our operations and business.
 
We are dependent upon information technology systems to run our operations. Our information technology systems are subject to disruption, damage or failure from a variety of sources, including, without limitation, computer viruses, security breaches, cyber-attacks, phishing attacks, natural disasters and design defects. Recently, energy facilities worldwide have been experiencing an increased number of cyber-attacks. Cybersecurity incidents, in particular, are constantly evolving and include malicious software, attempts to gain unauthorized access to data and other electronic security breaches that could lead to disruptions in systems, unauthorized release of confidential or otherwise protected information and to the corruption of data. Various measures have been implemented to minimize our risks related to information technology systems and network disruptions. However, given the unpredictability of the timing, nature and scope of information technology disruptions, we could potentially be subject to production downtimes, operational delays, the compromising of confidential or otherwise protected information, destruction or corruption of data, security breaches, other manipulation or improper use of our systems and networks or financial losses from remedial actions, any of which could have a material adverse effect on our competitive position, financial condition, results of operations or cash flows.
 
We maintain global information technology and communication networks and applications to support our business activities. Information technology security processes may not prevent future malicious actions, denial-of-service attacks, or fraud, resulting in corruption of operating systems, theft of commercially sensitive data, misappropriation of funds and businesses (also known as phishing) and operational disruption. Material system breaches and failures could result in significant interruptions that could in turn affect our operating results and reputation.
 
Negative impacts on biodiversity, including harming of protected species or other environmental hazards can result in curtailment of power plant operations, monetary fines and negative publicity.
 
Managing and operating large infrastructure assets may have a negative impact on biodiversity in the regions where we operate. In particular, the operation of wind and solar power plants can adversely affect endangered, threatened or otherwise protected animal species. Wind power plants involve a risk that protected species will be harmed, as the turbine blades travel at a high rate of speed and may strike flying animals (such as birds or bats) that happen to travel into the path of spinning blades. Solar power plants can also present a risk to animals.
 
Excessive killing of protected species or other environmental accidents or hazards could result in requirements to implement mitigation strategies, including curtailment of operations, and/or substantial monetary fines and negative publicity. We cannot guarantee that any curtailment of operations, monetary fines that are levied or negative publicity as a result of incidental killing of protected species and other environmental hazards will not have a material adverse effect on our business, financial condition, results of operations and cash flows.
 
We may be subject to litigation, other legal proceedings and tax inspections.
 
We are subject to the risk of legal claims and proceedings (including bankruptcy proceeding), requests for arbitration, tax inspections as well as regulatory enforcement actions in the ordinary course of our business and otherwise, including claims against our subsidiaries related to Abengoa or our subsidiaries not meeting their obligations. See “Item 4.B—Business Overview—Legal Proceedings.” The results of legal and regulatory proceedings or tax inspections cannot be predicted with certainty. We cannot guarantee that the results of current or future legal or regulatory proceedings, tax inspections or actions will not materially harm our operations, business, financial condition or results of operations, nor can we guarantee that we will not incur losses in connection with current or future legal or regulatory proceedings, tax inspections or actions that exceed any provisions we may have set aside in respect of such proceedings or actions or that exceed any available insurance coverage, which may have a material adverse effect on our business, financial condition, results of operations and cash flows. See “Item 4.B—Business Overview—Legal Proceedings.”
 
If we are deemed to be an investment company, we may be required to institute burdensome compliance requirements and our activities may be restricted, which may make it difficult for us to complete strategic acquisitions or effect combinations.
 
If we were deemed to be an investment company under the Investment Company Act of 1940 (the “Investment Company Act”) our business would be subject to applicable restrictions under the Investment Company Act, which could make it impractical for us to continue our business as contemplated. We believe our company is not an investment company under Section 3(b)(1) of the Investment Company Act because we are primarily engaged in a noninvestment company business, and we intend to conduct our operations so that we will not be deemed an investment company. However, if we were to be deemed an investment company, restrictions imposed by the Investment Company Act, including limitations on our capital structure and our ability to transact with affiliates, could make it impractical for us to continue our business as contemplated.
 

II.
Risks Related to the COVID-19 Pandemic
 
The outbreak of COVID-19 could have a material adverse impact on our business, financial condition, liquidity, results of operations, cash flows, cash available for distribution and ability to make cash distributions to our shareholders.
 
The COVID-19 outbreak was declared a pandemic by the World Health Organization in March 2020 and continues to spread in our key markets. The COVID-19 virus continues to evolve rapidly, and its ultimate impact is uncertain and subject to change. The geographies where Atlantica is present are going through subsequent waves of virus incidence. Governmental authorities have imposed or recommended measures or responsive actions, including quarantines of certain geographic areas and travel restrictions.
 
We cannot guarantee that the COVID-19 outbreak will not affect our operation and maintenance employees. Our operation and maintenance suppliers may also be affected by COVID-19 and the broader economic downturn. In addition, we may experience delays in certain operation and maintenance activities or certain activities may take longer than usual, or, in a worst case scenario, a potential outbreak at one of our assets may prevent our employees or our operation and maintenance suppliers’ employees from operating the plant. All these can hamper or prevent the operation and maintenance of our assets, which may result in a material adverse effect on our business, financial condition, results of operations and cash flows. Furthermore, COVID-19 has caused and may continue to cause travel restrictions and significant disruptions to global supply chains. A prolonged disruption could limit the availability of certain parts required to operate our facilities and adversely impact the ability of our operation and maintenance suppliers. If we were to experience a shortage of or inability to acquire critical spare parts, we could incur significant delays in returning facilities to full operation, which could negatively impact our business, financial condition, results of operations and cash flows.
 
Further, we have adopted additional precautionary measures intended to mitigate potential risks to our employees, including temporarily requiring all employees to work remotely when their work can be done from home, and suspending all non-essential travel. We have implemented protocols to decide which offices to maintain open and with what limitations, depending on the number of cases and other health indicators in each specific region.
 
In addition, COVID-19 and measures taken by governments are causing a slowdown of broad sectors of the economy, a general reduction in demand, including demand for commodities and a negative impact on prices of commodities, including electricity, oil and gas. In Spain, revenue received by our assets under the existing regulation depend to some extent on market prices for sale of electricity. During 2020, electricity market prices have been lower than in previous years. If this decline in market prices persisted over time, it could have a material adverse effect on our business, financial condition, results of operations and cash flows and the value of our renewable energy facilities may be impaired, or their useful life may be shortened.
 
The global outbreak also caused significant disruption and volatility in the global financial markets, including the market price of our shares, especially in March and April 2020. Debt markets have also been affected and there have been weeks with a very low number of new debt issuance transactions. Interest rates for new issuances and spreads with respect to treasury yields increased significantly in March until the beginning of May. Debt and equity markets could continue experiencing similar disruptions in the upcoming months since COVID-19 continues to have an impact on markets. A prolonged period of illiquidity and disruptions in the equity and credit markets could limit our ability to refinance our debt maturities and to finance our potential investments and acquisitions and execute on our growth strategy. Any prolonged and uncontained outbreak could result in further disruptions in the general economy and illiquidity in the credit markets. In addition, the progression of and global response to the COVID-19 outbreak could increase the risk of delays in such plans or in obtaining the financing required to close the acquisitions that we have announced.
 
Although our revenue is generally contracted or regulated, our clients may be affected by a reduced demand, lower commodity prices and the turmoil in the credit markets. A reduced demand and low prices persisting over time could cause delays in collections, a deterioration in the financial situation of our clients or their bankruptcy. For example, Pemex’s credit rating has weakened and is currently BBB from S&P, Ba2 from Moody’s and BB- from Fitch and its financial situation could worsen considering low oil prices in the past few months. We have been experiencing significant delays in collections in ACT since the second half of 2019 and we continue to monitor the situation closely. Our clients, including utilities, may face reduced revenue and may experience delays in collections from their own clients, as well as bad debt costs. Delays in collections from our clients can cause delays in distributions from our assets, which can cause a negative impact on our cash available for distributions and on our business, financial condition, results of operations, and cash flows. If our off-takers are unable or unwilling to fulfill their related contractual obligations, if they refuse to accept delivery of power delivered thereunder, if they otherwise terminate such agreements prior to the expiration thereof, if prices were re-negotiated under a bankruptcy situation, or if they delay payments, then our business, financial condition, results of operations and cash flows may be materially adversely affected.
 
We could also experience commercial disputes with our clients, suppliers and partners related to implications of COVID-19 in contractual relations. All the risks referred to can cause delays in distributions from our assets to the holding company level. In addition, we may experience delays in distributions due to logistic and bureaucratic difficulties to approve those distributions, which can negatively affect our cash available for distributions, our business, financial condition and cash flows. If we were to experience delays in distributions due to the risks described above and this situation persisted over time, we may fail to comply with financial covenants in our credit facilities and other financing agreements.
 
Additionally, many governments have implemented and will continue to implement stimulus measures to reduce the negative impact of COVID-19 in the economy. In many cases, these measures will increase government spending which may translate into increased tax pressure on companies in the countries where we operate. Changes in corporate tax rates and/or other relevant tax laws may have a material adverse effect on our business, financial condition, results of operations and cash flows.
 
There are various uncertainties associated with the COVID-19 outbreak. We do not yet have sight over the full extent of the virus’ potential effects on our business or the global economy as a whole, or the effectiveness of the vaccines that have recently been become available in the EU, the United States or the United Kingdom. We continue to monitor the situation and adjust our current policies and practices as more information and guidance become available.
 

III.
Risks Related to Our Relationship with Algonquin and Abengoa
 
Algonquin is our largest shareholder and exercises substantial influence over us.
 
Currently, Algonquin beneficially owns 44.2% of our ordinary shares and is entitled to vote approximately 41.5% of our ordinary shares. As a result of this ownership, Algonquin has substantial influence on our affairs and their ownership interest and voting power constitute a significant percentage of the shares eligible to vote on any matter requiring the approval of our shareholders. Such matters include the election of directors, the adoption of amendments to our articles of association and approval of mergers or sale of all or a high percentage of our assets.
 
Further, our reputation is closely related to that of Algonquin. Any damage to the public image or reputation of Algonquin as a result of adverse publicity, poor financial or operating performance, changes in financial condition, decline in the price of its shares or otherwise could have a material adverse effect on our business, financial condition, results of operations and cash flows.
 
This concentration of ownership may also have the effect of discouraging others from making tender offers for our shares. There can be no assurance that the interests of Algonquin will coincide with the interests of the purchasers of our shares or that Algonquin will act in a manner that is in our best interests. If Algonquin sells its shares to a single shareholder, that new shareholder could continue to exercise substantial influence and could seek to influence or change our strategy or corporate governance or could take effective control of us. In addition, we have limited knowledge and visibility of Algonquin’s operations and plans.
 
Our ownership structure and certain service agreements may create significant conflicts of interest that may be resolved in a manner that is not in our best interests.
 
Our ownership structure involves several relationships that may give rise to certain conflicts of interest between us, Algonquin, and the rest of our shareholders. Currently, two of our directors are officers of Algonquin.
 
Currently, AAGES and Algonquin are related parties and may have interests that differ from our interests, including with respect to the types of investments and acquisitions made, the timing and amount of dividends paid by us, the reinvestment of returns generated by our operations, the use of leverage when making acquisitions and the appointment of outside advisors and service providers. Any transaction between us and AAGES or Algonquin (including the acquisition of any ROFO assets or any co-investment with AAGES or Algonquin or any investment on an Algonquin asset) is subject to our related party transactions policy, which requires prior approval of such transaction by the related party transactions committee, which is composed of independent directors. The existence of our related party transactions approval policy may not insulate us from derivative claims related to related party transactions and the conflicts of interest described in this risk factor. Regardless of the merits of such claims, we may be required to spend significant management time and financial resources in the defense thereof. Additionally, to the extent we fail to appropriately deal with any such conflicts, it could negatively impact our reputation and ability to raise additional funds and the willingness of counterparties to do business with us, all of which may have a material adverse effect on our business, financial condition, results of operations and cash flows.
 
If Abengoa defaults on certain of its debt obligations, including as a result of the recent insolvency filing by their holding company Abengoa S.A., we could potentially be in default of certain of our project financing agreements.
 
Abengoa, which is currently our largest supplier and used to be our largest shareholder, went through a restructuring process which started in November 2015 and ended in March 2017, obtained approval for a second restructuring in July 2019 and Abengoa S.A. has recently filed for insolvency again. On May 19, 2020, Abengoa announced that it was working on a new viability plan that would include new financing under a COVID-19 mitigation program in Spain, as well as renegotiation of certain existing debt with suppliers and lenders. Within this process on August 18, 2020 Abengoa filed pre-insolvency proceedings for the individual company Abengoa, S.A(the holding company). According to public communications to the Spanish securities market regulator, Abengoa believed this filing should not affect the restructuring plan for which Abengoa is currently seeking approval from its creditors. On February 22, 2021, Abengoa, S.A. filed for insolvency proceedings in Spain. Based on the public information filed in connection with these proceedings, such insolvency proceedings do not include other Abengoa companies, including Abenewco1, S.A., the controlling company of the subsidiaries performing the operation and maintenance services for us.
 
The project financing arrangement for Kaxu contains cross-default provisions related to Abengoa such that debt defaults by Abengoa, subject to certain threshold amounts and/or a restructuring process, could trigger a default under the Kaxu project financing arrangement. In March 2017, Atlantica obtained a waiver with respect to its Kaxu project financing arrangement which waives any potential cross-defaults by Abengoa up to that date, but the waiver did not cover potential future cross-default events. The restructuring process and the pre-insolvency filing by the individual company Abengoa S.A. in August 2020 represent a theoretical event of default under the Kaxu project finance agreement. In December 2020, we obtained a waiver from Kaxu’s project debt lenders in which they commit not to take any action until December 31, 2021 with respect to any potential cross-defaults with Abengoa for the pre-insolvency filing of August 2020. The insolvency filing by the individual company Abengoa S.A. in February 2021 represents a theoretical event of default under the Kaxu project finance agreement for which we do not yet have a waiver. Although we do not expect the Kaxu’s project debt lenders to accelerate the debt or take any other action, a cross-default scenario, if not cured or waived, may entitle lenders to demand repayment, limit distributions from the asset or enforce on their security interests, which may have a material adverse effect on our business, financial condition, results of operations and cash flows. We are negotiating a waiver from the creditors and/or contractual modifications to permanently remove the cross-default provision.
 
Abengoa’s financial condition including the recent insolvency filing by Abengoa S.A. could affect its ability to satisfy its obligations with us under different agreements, such as operation and maintenance agreements as well as indemnities and other contracts in place, and may affect our reputation.
 
We have current and future collection rights with certain subsidiaries of Abengoa. Moreover, Abengoa has several obligations and indemnities which have resulted or could result in additional liability obligations to us or to our assets. Inability of Abengoa to pay their obligations when due, including as a result of insolvency,  would have a negative impact on our current or future cash position.
 
The insolvency filing by the individual company Abengoa, S.A. in February 2021 may cause an insolvency filing of Abenewco1, S.A., the controlling company of the subsidiaries performing the operation and maintenance services, or insolvency filings of subsidiaries of Abenewco1, S.A. There may be unanticipated consequences of Abengoa S.A. insolvency filings, Abenewco1 potential filing, further restructurings by Abengoa or ongoing bankruptcy proceedings by Abengoa’s subsidiaries that we have not yet identified. There are uncertainties as to how any further bankruptcy proceedings would be resolved and how our relationship with Abengoa would be affected following the initiation or resolution of any such proceedings.
 
A deterioration in the financial position of Abengoa and of certain of its subsidiaries may result in a material adverse effect on certain of our operation and maintenance agreements. Abengoa and its subsidiaries provide operation and maintenance services for some of our assets. We cannot guarantee that Abengoa and/or its subcontractors will be able to continue performing with the same level of service (or at all) and under the same terms and conditions, and at the same prices.
 
Because we have long-term operation and maintenance agreements with Abengoa for many of our assets, if Abengoa cannot continue performing current services at the same prices, we may need to renegotiate contracts and pay higher prices or change the scope of the contracts. This could also cause us to change suppliers or to pay higher prices or change the level of services. This may have a material adverse effect on our business, financial condition, results of operations and cash flows.
 
The insolvency filing by Abengoa S.A. in February 2021, the potential insolvency filing by Abenewco1, S.A. (or any of its subsidiaries), a deterioration in the financial situation of Abengoa or the implementation of a new viability plan may also result in a material adverse effect on Abengoa’s and its subsidiaries’ obligations, warranties and guarantees, and indemnities covering, for example, potential tax liabilities for assets acquired from Abengoa, or any other agreement. In addition, Abengoa has represented that we would not be a guarantor of any obligation of Abengoa with respect to third parties. Abengoa agreed to indemnify us for any penalty claimed by third parties resulting from any breach in Abengoa’s representations. Certain of these indemnities and obligations are no longer valid after the insolvency filing by Abengoa, S.A. in February 2021. A potential insolvency of Abenewco1, S.A. may also terminate the remaining obligations, indemnities and guarantees. In addition, in Mexico, Abengoa owns a power plant that shares certain infrastructure and has certain back-to-back obligations with ACT. A deterioration in Abengoa’s or this asset’s financial situation may also result in a material adverse effect on ACT and on our business, financial condition, results of operations and cash flows.
 
In January 2019, we entered into an agreement with Abengoa under the Abengoa ROFO Agreement for the acquisition of Tenes and paid $19.9 million as an advance payment. Closing of the acquisition was subject to conditions precedent which were not fulfilled. In accordance with the terms of the share purchase agreement, the advance payment was converted into 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. In October 2019, we received a first payment of $7.8 million through the cash sweep mechanism. On May 31, 2020, we entered into a new $4.5 million secured loan agreement with Befesa Agua Tenes. This new loan is expected to be reimbursed no later than May 31, 2032, together with 12% interest per annum, through a full cash-sweep of all the dividends to be received from the asset. Although our investment was structured to survive Abengoa’s potential bankruptcy, we cannot guarantee this will be the case, which may have an adverse effect on our results of operations and cash flows.
 
In addition, although Abengoa has not been our shareholder since the end of 2018, in some geographies our reputation continues to be related to that of Abengoa. Any damage to the public image or reputation of Abengoa as a result of bankruptcy, adverse publicity, poor financial or operating performance, changes in financial condition, or otherwise could have a material adverse effect on our business, financial condition, results of operations and cash flows.
 
By virtue of initiating a bankruptcy filing under the Spanish Insolvency Act, Abengoa may be subject to insolvency claw-back actions in which transactions may be set aside.
 
Under the Spanish Insolvency Act, the transactions a company has entered into during the two years prior to the opening of insolvency proceedings can be set aside, irrespective of whether there was intent to defraud, if those transactions are considered materially damaging to the insolvency estate. Material damage is assessed on the basis of the circumstances at the time the transaction was carried out, without the benefit of hindsight and without considering subsequent events or occurrences, including events in relation to insolvency proceedings or the request to set-aside the transaction. Transactions we have entered into with Abengoa in the previous two years before it may be declared insolvent (if such action were to take place) could be set aside. The court would consider if the transactions were detrimental to Abengoa on the terms on which they were made and the suitability of the transactions at the time they were entered into, if the transaction followed market standards and prices and if it had real economic value.
 
In practice, transactions that are subject to claw-back relate to: (a) unjustified payments or advances from the insolvent company to another group company, (b) transfers of assets or rights by the insolvent company to another group company at below market value, (c) payment-in-kind arrangements in which the property another group company receives in payment is higher in value than the debt owed to it, and (d) security provided by the insolvent company for another group company’s obligations. This determination will be a question of fact before a Spanish court if Abengoa initiates a bankruptcy filing in Spain, however if any of the transactions entered into between us and Abengoa, including those related to drop-downs assets, were declared invalid by a Spanish court, unless it is determined we acted in bad faith, such transaction would be unwound and we would receive back the cash paid, which may have a material adverse effect on our business, financial condition, results of operations and cash flows.
 
On February 22, 2021, Abengoa, S.A. filed for insolvency proceedings in Spain. Based on the public information filed in connection with these proceedings, such insolvency proceedings do not include other Abengoa companies, including Abenewco1, S.A., the controlling company of the subsidiaries performing the operation and maintenance services for us. The outcome of any bankruptcy proceedings initiated by Abengoa would be difficult to predict given that Abengoa is incorporated in Spain and has assets and operations in several countries around the world. Bankruptcy laws other than those of Spain could apply. The rights of Abengoa’s creditors may be subject to the laws of a number of jurisdictions and such multi-jurisdictional proceedings are typically complex and often result in substantial uncertainty. In addition, the bankruptcy and other laws of such jurisdictions may be materially different from, or in conflict with, one another. If Abengoa is subject to U.S. bankruptcy law, bankruptcy courts in the United States may seek to assert jurisdiction over all of its assets, wherever located, including property situated in other countries.
 
A bankruptcy filing by Abengoa may permanently affect Abengoa’s operations. We cannot predict how any bankruptcy proceeding would be resolved or how our relationship with Abengoa will be affected following the initiation of any such proceedings or after the resolution of any such proceedings. Any bankruptcy proceedings initiated by Abengoa may have a material adverse effect on our business, financial condition, results of operations and cash flows.
 

IV.
Risks Related to Our Indebtedness
 
Our indebtedness could limit our ability to react to changes in the economy or our industry, expose us to the risk of increased interest rates and limit our activities due to covenants in existing financing agreements. It could also adversely affect our ability to make distributions from the project subsidiaries to Atlantica Sustainable Infrastructure plc, our ability to fund our operations, pay dividends or raise additional capital.
 
As of December 31, 2020, we had (i) $5,237.6 million of total indebtedness under various project-level debt arrangements and (ii) $993.7 million of total indebtedness under our corporate arrangements, which include the Note Issuance Facility 2019, the Note Issuance Facility 2020, the 2020 Green Private Placement, the Green Exchangeable Notes and drawdowns under the Revolving Credit Facility. In addition, we may incur in the future additional project-level debt and corporate debt.
 
Our substantial debt could have important negative consequences on our business financial condition, results of operation and cash flows including:
 

increasing our vulnerability to general economic and industry conditions;
 

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

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

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

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

exposing us to the risk of increased interest rates because a portion of some of our borrowings (below 10% as of December 31, 2020 after giving effect to hedging agreements) are at variable rates of interest;
 

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

limiting our ability to adjust to changing market conditions and placing us at a disadvantage compared to our competitors who have less debt.
 
The operating and financial restrictions and covenants in the Revolving Credit Facility, the Note Issuance Facility 2019, the Green Private Placement and the Note Issuance Facility 2020 may adversely affect our ability to finance our future operations or capital needs, to engage in other business activities that may be in our interest and to execute our business strategy as we intend to do so. Each contains covenants that limit certain of our, the guarantors’ and other subsidiaries’ activities. If we breach any of these covenants (including as a result of our inability to satisfy certain financial covenants), a default may result which may entitle the related noteholders or lenders, as applicable to demand repayment and accelerate all such debt or to enforce their security interests, which would have a material adverse effect on our business, financial condition, results of operations and cash flows. See “Item 5.B—Operating and Financial Review and Prospects—Liquidity and Capital Resources—Financing Arrangements.”
 
In addition, our inability to satisfy certain financial covenants may prevent cash distributions by the particular project(s) and other subsidiaries to us. If our project-level and other subsidiaries are unable to make distributions, it would likely have a material adverse effect on our ability to serve debt at the corporate level or pay dividends to holders of our shares. Our failure to comply with those and other covenants could result in an event of default which, if not cured or waived, may entitle the related noteholders or lenders, as applicable to demand repayment or to enforce their security interests, which may have a material adverse effect on our business, financial condition, results of operations and cash flows. In addition, failure to comply with such covenants, may entitle the related noteholders or lenders, as applicable, to demand repayment and accelerate all such indebtedness.
 
Letter of credit facilities or bank guarantees to support project-level contractual obligations generally need to be renewed, at which time we will need to satisfy applicable financial ratios and covenants. If we are unable to renew the letters of credit as expected or replace them with letters of credit under different facilities on favorable terms or at all, we may experience a material adverse effect on our business, financial condition, results of operations and cash flows. Furthermore, such inability may constitute a default under certain project-level financing arrangements, restrict the ability of the project-level subsidiary to make distributions to us and/or reduce the amount of cash available at such subsidiary to make distributions to us.
 
We may not be able to refinance our existing indebtedness.
 
Our ability to arrange financing, either at corporate level or at a project-level, and the costs of such capital, are dependent on numerous factors, including:
 

general economic and capital market conditions;

credit availability from banks and other financial institutions;

investor confidence in us and Algonquin as our largest shareholder

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

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

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

tax and securities laws that may impact raising capital.
 
We may not be successful in obtaining additional capital for these or other reasons. Furthermore, we may be unable to refinance or replace project-level financing arrangements or other credit facilities on favorable terms or at all upon the expiration or termination thereof. We may be unable to repay our existing debt as it becomes due if we fail, or any of our projects fails, to obtain additional capital or enter into new or replacement financing arrangements, which would have a material adverse effect on our business, financial condition, results of operations and cash flows.
 
We may not be able to arrange the required or desired financing for investments and acquisitions and for the successful refinancing of the Company’s project level and corporate level indebtedness.
 
The global capital and credit markets have experienced in the past and may continue to experience periods of extreme volatility and disruption. In recent years, capital markets have experienced periods of high volatility, particularly in the United States and Europe. At times, our access to financing was curtailed by market conditions and other factors. Continued disruptions, uncertainty or volatility in the global capital and credit markets may limit our access to additional capital required to refinance our debt on satisfactory terms or at all, may limit our ability to replace, in a timely manner, maturing liabilities, and may limit our access to new debt and equity capital to make further investments acquisitions. Volatility in debt markets may also limit our ability to fund or refinance many of our projects and corporate level debt, even in cases where such capital has already been committed. As a result, we may be forced to delay raising capital, issue shorter-term securities than we prefer, or bear a higher cost of capital which could decrease our profitability and significantly reduce our financial flexibility or even require us to modify our dividend policy. In the event we are required to replace previously committed financing to certain projects that subsequently becomes unavailable, we may have to postpone or cancel planned acquisitions, investments or capital expenditures. The inability to raise capital, higher costs of capital or postponement or cancellation of planned acquisitions, investments or capital expenditures may have a materially adverse effect on our business, financial condition, results of operations and cash flows. If financing is available, utilization of our credit facilities, debt securities or project level financing for all or a portion of the purchase price of an acquisition, as applicable, could significantly increase our interest expense and debt repayment, impose additional or more restrictive covenants, and reduce cash available for distribution.
 
We may be subject to increased finance expenses if we do not effectively manage our exposure to interest rate and foreign currency exchange rate risks.
 
We are exposed to various types of market risk in the normal course of business, including the impact of interest rate changes and foreign currency exchange rate fluctuations. Some of our indebtedness (including project-level indebtedness) bears interest at variable rates, generally linked to market benchmarks such as EURIBOR and U.S. LIBOR. Any increase in interest rates would increase our finance expenses relating to our variable rate indebtedness and increase the costs of refinancing our existing indebtedness and issuing new debt.
 
In addition, although most of our long-term contracts are denominated in, indexed or hedged to U.S. dollars, we conduct our business and incur certain costs in the local currency of the countries in which we operate. In addition, the revenues, costs and debt of our solar assets in Spain are denominated in euros. Since the beginning of 2017, we have maintained euro-denominated debt at the corporate level. Interest payments in euros and our euro denominated general and administrative expenses create a natural hedge for a portion of the distributions from Spanish assets. Our strategy is to hedge the exchange rate for the distributions from our Spanish assets after deducting euro-denominated interest payments and euro-denominated general and administrative expenses. Through currency options, we hedge on a rolling basis 100% of the net euro net exposure for the next 12 months and 75% of the net euro net exposure for the following 12 months. See “Item 5.A—Operating and Financial Review—Results of Operations—Factors Affecting our Results of Operations.”
 
As we continue expanding our business, an increasing percentage of our revenue and cost of sales may be denominated in currencies other than our reporting currency, the U.S. dollar. Under that scenario, we would become subject to increasing currency exchange risk, whereby changes in exchange rates between the U.S. dollar and the other currencies in which we do business could result in foreign exchange losses.
 
In addition, we seek to actively work with lending financial institutions to mitigate our interest rate risk exposure and to secure lower interest rates by entering into interest rate options and swaps. As a matter of policy, we seek to cover at least 70% of our outstanding long-term project debt interest rate risk. We estimate that approximately 93% of our total interest risk exposure was fixed or hedged as of December 31, 2020.
 
If our risk-management strategies are not successful in limiting our exposure to changes in interest rates and foreign currency exchange rates our business, financial condition, results of operations and cash flows maybe materially adversely affected.
 
Potential future defaults by our subsidiaries, our off-takers, our suppliers, Abengoa or other persons could adversely affect us.
 
The financing agreements of our project subsidiaries are primarily loan agreements which provide that the repayment of the loans (and interest thereon) is secured solely by the shares, physical assets, contracts and cash flow of that project company. This type of financing is usually referred to herein as “project debt.” As of December 31, 2020, we had $5,237.6 million of outstanding indebtedness under various project-level debt arrangements.
 
While the lenders under our project debt do not have direct recourse to us or our subsidiaries (other than the letter of credit and bank guarantee facilities), defaults by the project borrowers under such financings can still have important consequences for us and our subsidiaries, including, without limitation:
 

reducing our receipt of dividends, fees, interest payments, loans and other sources of cash, since the project company will typically be prohibited from distributing cash to us and our subsidiaries until the event of default is cured or waived;
 

default under our other debt instruments;
 

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

the loss or impairment of investors’ and project finance lenders’ confidence in us.
 
If we fail to satisfy any of our debt service obligations or breach any related financial or operating covenants, the applicable lender could declare the full amount of the relevant project debt to be immediately due and payable and could foreclose on any assets pledged as collateral.
 
In addition, the project financing arrangement for Kaxu contains cross-default provisions related to Abengoa such that debt defaults by Abengoa, subject to certain threshold amounts and/or a restructuring process, could trigger a default under the Kaxu project financing arrangement. The insolvency filing by the individual company Abengoa, S.A. in February 2021 represents a theoretical event of default under the Kaxu project finance agreement for which we do not yet have a waiver. Although we do not expect the Kaxu’s project debt lenders to accelerate the debt or take any other action, a cross-default scenario, if not cured or waived, may entitle lenders to demand repayment, limit distributions from the asset or enforce on their security interests, which may have a material adverse effect on our business, financial condition, results of operations and cash flows. See “If Abengoa defaults on certain of its debt obligations, we could potentially be in default of certain of our project financing agreements.”
 
Under the Revolving Credit Facility, the Note Issuance Facility 2019, the Green Private Placement and the Note Issuance Facility 2020, a payment default with respect to indebtedness having an aggregate principal amount above certain thresholds by us, any guarantor thereof or one or more of our non-recourse subsidiaries representing more than 25% of the cash available for distribution distributed in the previous four fiscal quarters could trigger a default.
 
Any of these events may have a material adverse effect on our business, financial condition, results of operations and cash flows.
 
Uncertainty relating to the LIBOR calculation process and potential phasing out of LIBOR in the future may adversely affect the value of any outstanding debt instruments.
 
National and international regulators and law enforcement agencies have conducted investigations into a number of rates or indices known as “reference rates.” Actions by such regulators and law enforcement agencies may result in changes to the manner in which certain reference rates are determined, their discontinuance, or the establishment of alternative reference rates. In particular, on July 27, 2017, the Chief Executive of the U.K. Financial Conduct Authority (the “FCA”), which regulates LIBOR, announced that the FCA will no longer persuade or compel banks to submit rates for the calculation of LIBOR after 2021. Such announcement indicates that the continuation of LIBOR on the current form cannot and will not be guaranteed after 2021. As a result, it appears highly likely that LIBOR will be discontinued or modified by 2021. On May 31, 2019, the Alternative Reference Rates Committee (“ARRC”) published their final recommendations for new guidelines for LIBOR securitizations, which has been well-received by the securities market. The ARRC proposed that the Secured Overnight Financing Rate (“SOFR”) is the rate that represents best practice as the alternative to USD-LIBOR for use in derivatives and other financial contracts that are currently indexed to USD-LIBOR. SOFR is a more generic measure than LIBOR and considers the cost of borrowing cash overnight, collateralized by U.S. Treasury securities. Whether or not SOFR will attain market traction as a LIBOR replacement tool remains in question. As such, the future of LIBOR at this time is uncertain, including whether the COVID-19 pandemic will have further effect on LIBOR transition plans. In preparation for the potential phase out of LIBOR starting in 2021, we may need to renegotiate our financial obligations and derivative instruments linked to LIBOR.
 
Given the inherent differences between LIBOR and SOFR or any other alternative benchmark rate that may be established, there are many uncertainties regarding a transition from LIBOR. At this time, it is not possible to predict the effect that these developments, any discontinuance, modification or other reforms to LIBOR or any other reference rate, or the establishment of alternative reference rates may have on LIBOR, other benchmarks, or LIBOR-based debt instruments. Furthermore, the use of alternative reference rates, including SOFR, or other reforms could cause the interest rate calculated for the LIBOR-based debt instruments to be materially different than expected. As of December 31, 2020, total notional amount of debt referenced to LIBOR was approximately $1,165.8 million and total notional amount of derivatives hedging this debt, thus indexed to LIBOR as well was approximately $618.8 million.
 
A change of control or a delisting of our shares may have negative implications for us.
 
If any investor acquires over 50.0% of our shares or if our ordinary shares cease to be listed on the NASDAQ or a similar stock exchange, we may be required to refinance all or part of our corporate debt or obtain waivers from the related noteholders or lenders, as applicable, due to the fact that all of our corporate financing agreements contain customary change of control provisions and delisting restrictions. If we fail to obtain such waivers and the related noteholders or lenders, as applicable, elect to accelerate the relevant corporate debt, we may not be able to repay or refinance such debt (on favorable terms or at all), which may have a material adverse effect on our business, financial condition results of operations and cash flows. Additionally, in the event of a change of control we could see an increase in the yearly state property tax payment in Mojave, which would be reassessed by the tax authority at the time the change of control potentially occurred. Our best estimate with current information available and subject to further analysis is that we could have an incremental annual payment of property tax of approximately $12 million to $14 million, which could potentially decrease progressively over time as the asset depreciates.
 

V.
Risks Related to Our Growth Strategy
 
We may not be able to identify or consummate future investments and acquisitions on favorable terms, or at all.
 
Our business strategy includes growth through the acquisition of additional revenue-generating assets and investments in projects under development or construction. This strategy depends on our ability to successfully identify and evaluate investment opportunities and consummate acquisitions on favorable terms. The number of investment opportunities may be limited.
 
Our ability to acquire future renewable energy projects or businesses depends on the viability of renewable energy projects generally. These projects are in some cases contingent on public policy mechanisms including, among others, ITCs, cash grants, loan guarantees, accelerated depreciation, expensing for certain capital expenditures, carbon trading plans, environmental tax credits and research and development incentives. See “—Government regulations could change at any time and such changes may negatively impact our current business and our growth strategy.” Our ability to consummate future investments and acquisitions may also depend on our ability to obtain any required government or regulatory approvals for such investments, including, but not limited to, the Federal Energy Regulatory Commission, or FERC, approval under Section 203 of the FPA in respect of investments in the United States; or any other approvals in the countries in which we may purchase assets in the future. We may also be required to seek authorizations, waivers or notifications from debt and/or equity financing providers at the project or holding company level; local or regional agencies or bodies; and/or development agencies or institutions that may have a contractual right to authorize a proposed acquisition.
 
Furthermore, we will compete with other local and international companies for acquisition opportunities from third parties, which may increase our cost of making investments or cause us to refrain from making acquisitions from third parties. Some of our competitors for investments and acquisitions are much larger than us, with substantially greater resources. These companies may be able to pay more for acquisitions due to cost of capital advantages, potential synergies or other drivers, and may be able to identify, evaluate, bid for and purchase a greater number of assets than our financial or human resources permit. If we are unable to identify and consummate future acquisitions, it will impede our ability to execute our growth strategy and limit our ability to increase the amount of dividends paid to holders of our shares.
 
Our ability to consummate future investments and acquisitions also depends on the availability of financing. See “—We may not be able to arrange the required or desired financing for acquisitions.”
 
Finally, demand for renewable energy may be affected by the cost of other energy sources. To the extent renewable energy becomes less cost-competitive, demand for renewable energy could decrease. Slow growth or a long-term reduction in the energy demand could cause a reduction in the development of renewable energy programs projects. Decreases in the prices of electricity could affect our ability to acquire assets, as renewable energy developers may not be able to compete with providers of other energy sources at such lower prices. Our inability to acquire assets could have a material adverse effect on our ability to execute our growth strategy.
 
Our ability to grow organically is limited to some assets which have inflation indexation mechanisms in its revenues, to our transmission lines and to some renewable assets. We may not be able to deliver organic growth.
 
Our ability to grow through investments and acquisitions depends, in part, on AAGES’ and Algonquin’s ability to present us with investment opportunities. AAGES and Algonquin may not offer us assets at all or may not offer us assets that fit within our portfolio or contribute to our growth strategy. Only certain assets outside the United States and Canada are included in the Algonquin ROFO Agreement. AAGES and Algonquin may decide to keep assets subject to our ROFO Agreements in their portfolios and not offer them to us for acquisition. Algonquin can terminate its ROFO agreement with us with a 180-day notice. Additionally, we may not reach an agreement on the price of assets offered by AAGES or Algonquin. For these reasons, we may not be able to consummate future investments from AAGES or Algonquin, which may restrict our ability to grow.
 
Furthermore, AAGES or Algonquin may have financial and resource constraints limiting or eliminating their ability to continue building the contracted assets which are currently under construction and may have financial and resource constraints limiting or eliminating their ability to develop and build new contracted assets. In addition, AAGES or Algonquin may sell assets under development, before they reach their commercial operation date. Some of the assets subject to the ROFO Agreements may not be attractive enough to us for different reasons.
 
We have reached agreements with new partners that develop assets in the geographies in which we operate. We expect that these agreements will be a source of growth in addition to AAGES and Algonquin, however we cannot guarantee that our investments will be successful and that our growth expectations will materialize. Additionally, we cannot guarantee that we will be successful in identifying new potential partners or that we will be able to acquire additional assets from those partners in the future. If we are unable to identify and reach new agreements on favorable terms with new partners with suitable assets, or unable to consummate future acquisitions from any such sponsor, it may limit our ability to execute our growth strategy and may have a materially adverse effect on our business, financial condition, results of operation and cash flows.
 
Furthermore, development and construction activities are subject to failure rate and different types of risks. If we co-invest with partners, or on our own, in assets under development or construction, we cannot guarantee that the development and construction of the asset will be successful and that we end up owning an operational asset.
 
All the above could limit our ability to grow, which may have a material adverse effect on our business, financial condition, results of operations and cash flows.
 
In order to grow our business, we may invest in or acquire assets or businesses which have a higher risk profile or are less ESG-friendly than certain assets in our current portfolio.
 
In order to grow our business, we may acquire assets and businesses which may have a higher risk profile than certain of the assets we currently own. Competition to acquire contracted assets in operation has been high in recent years and is expected to continue being so. As a result, we have announced investments with exposure to development and construction risk. We intend to continue investing in assets which are not currently in operation and which are subject to development and construction risk. Construction of renewable assets, among others, is subject to risk of cost overruns and delays. There can be no assurances that assets under development and construction will perform as expected or that the returns will be as expected. In addition, we may consider acquiring business which are not contracted, including regulated businesses, which are subject to demand risk. We may also consider acquiring assets which are not contracted or not fully contracted, for which revenues will depend on the price of the electricity and which are subject to merchant risk. We have recently invested and may consider investing in business sectors where we do not have previous experience and may not be able to achieve the expected returns. We may also consider investing with partners or on our own in new technologies which do not have for the moment a track record as proven as our current assets, such as storage, district heating or geothermal. Furthermore, we may consider acquiring assets with revenues not denominated in US dollars or euros, which would increase our exposure to local currency, and which could generate higher volatility in the cash flows we generate. In all these types of assets and businesses, the risk of not meeting the expected cash flow generation and expected returns is higher than in contracted assets. In addition, these type of assets and businesses could present a higher variability in the cash flows they generate. In addition, we may acquire assets which may be considered as less ESG-friendly than certain assets in our current portfolio by current and potential investors. For example, considering the competitive landscape for renewable assets in recent years, we may acquire additional natural gas assets. Although we have set a target to maintain at least 80% of our Adjusted EBITDA generated by low carbon footprint assets, some investors with a focus on ESG may consider this target insufficient, which could cause us to become less attractive to investors.
 
As a result, the consummation of investments and acquisitions may have a material adverse effect on our ability to grow, our business, financial condition, results of operations and cash flows.
 
We cannot guarantee the success of our recent and future investments and acquisitions.
 
Acquisitions of and investments in companies and assets are subject to substantial risks, including the failure to identify material problems during due diligence (for which we may not be indemnified post-closing), the risk of over-paying for assets (or not making acquisitions on an accretive basis) and the ability to retain customers. Furthermore, the integration and consolidation of acquisitions requires substantial human, financial and other resources and, ultimately, our acquisitions may divert management’s attention from our existing business concerns, disrupt our ongoing business or not be successfully integrated at all. There can be no assurances that any future acquisitions will perform as expected or that the returns will be as expected. As a result, the consummation of acquisitions may have a material adverse effect on our ability to grow, our business, financial condition, results of operations and cash flows.
 
We may be unable to complete all, or any, such transactions that we may analyze. Even where we consummate acquisitions, we may be unable to achieve projected cash flows; recognize unexpected liabilities or costs; or encounter regulatory complications arising from such transactions. Furthermore, the terms and conditions of financing for such acquisitions or financial investments could restrict the manner in which we conduct our business. These risks could have a material adverse effect on our business, financial condition, results of operations and cash flows.
 
We may not be able to close some of the acquisitions that we have recently announced. In some of these acquisitions, we have signed a share purchase agreement, but closing of the acquisition is subject to closing conditions and authorizations. For example, in the acquisition of PTS, we initially acquired a 5% ownership in the project and have an agreement to acquire an additional 65% stake subject to the asset entering into commercial operation, non-recourse project financing being closed and final approvals and customary conditions, including the absence of material adverse effects. In addition, our partner in this asset is negotiating to sell part of its business, which may include the company that renders operation and maintenance services to PTS. This sale may require change of control waivers and may make closing of the acquisition more difficult. We cannot guarantee that we will close this acquisition or that closing will occur on the terms originally agreed. In the acquisitions of PTS, Calgary District Heating and Coso, closing is also subject to regulatory approvals.
 
In addition, some of the transactions we have announced are acquisitions of assets under development or construction. Although our construction risk is limited, taking into account the nature of the assets and protection clauses in the share purchase agreements, there could be delays in construction and cost overruns not covered by the protection clauses in the relevant share purchase agreement, which may restrict us to get to the expected CAFD in the assets we are acquiring.
 
We may also make acquisitions or investments in assets that are located in different jurisdictions and are different from, and may be riskier than, those jurisdictions in which we currently operate (Canada, the United States, Mexico, Peru, Chile, Uruguay, Spain, South Africa and Algeria). See “—We have international operations and investments, including in emerging markets that could be subject to economic, social and political uncertainties.” These changes may have a material adverse effect on our business, financial condition, results of operations and cash flows.
 
Our cash dividend policy may limit our ability to grow and make acquisitions and investments through cash on hand.
 
Our dividend policy is to distribute a high percentage of our cash available for distribution, after corporate general and administrative expenses and cash interest payments and less reserves for the prudent conduct of our business, each quarter and to rely primarily upon external financing sources, including the issuance of debt and equity securities as well as borrowings under credit facilities to fund our acquisitions, investments and potential growth capital expenditures. We may be precluded from pursuing otherwise attractive investments if the projected short-term cash flow from the acquisition or investment is not adequate to service the capital raised to fund the investment, after giving effect to our available cash reserves.
 
Because of our dividend policy, our growth may not be as fast as that of businesses that reinvest their available cash to expand ongoing operations. To the extent we issue additional equity securities in connection with any acquisitions or growth capital expenditures, the payment of dividends on these additional equity securities may increase the risk that we will be unable to maintain or increase our per share dividend. There are no limitations in our articles of association on our ability to issue equity securities, including convertible bonds, preferred shares or other securities ranking senior to our shares.
 

VI.
Risks Related to the Markets in Which We Operate
 
Difficult conditions in the global economy and in the global capital markets have caused, and may continue to cause, a sharp reduction in worldwide demand for our products and services
 
Our results of operations have been, and continue to be, materially affected by conditions in the global economy. In the United States, capital markets have been experiencing some volatility recently. Concerns over the COVID-19 pandemic and its effects on the global economy, volatile oil and gas prices, geopolitical issues, the availability and cost of credit, sovereign debt and the instability of the euro have contributed to increased volatility in capital markets and worsened expectations for the economy. Adverse events and continuing disruptions in the global economy and capital markets may have a material adverse effect on our business, financial condition, results of operations and cash flows. Moreover, even in the absence of a market downturn, we are exposed to risk of loss due to market volatility and other factors, including volatile oil prices, interest rates, consumer spending, business investment, government spending, or inflation, among others, that could affect the economic and financial situation of our concession contracts’ counterparties and, ultimately, the profitability and growth of our business.
 
Generalized or localized downturns or inflationary or deflationary pressures in our key geographical areas could also have a material adverse effect on our business, financial condition, results of operations and cash flows. A significant portion of our business activity is concentrated in the United States, Mexico, Peru and Spain. Consequently, we are significantly affected by the general economic conditions in these countries. Spain, for instance, is facing a recession in the last quarters caused by the COVID-19 pandemic that is worsening high unemployment and significant government debt. The effects on the European and global economy of the COVID-19 pandemic, or the exit of the United Kingdom from the European Union or of any other member states from the Eurozone, the dissolution of the euro, or the perception that any of these events are imminent, are inherently difficult to predict and could give rise to operational disruptions or other risks of contagion to our business and have a material adverse effect on our business, financial condition, results of operations and cash flows. In addition, to the extent uncertainty regarding the European economic recovery continues to negatively affect government or regional budgets, our business, financial condition, results of operations and cash flows could be materially adversely affected.
 
We have international operations and investments, including in emerging markets that could be subject to economic, social and political uncertainties.
 
We operate our activities in a range of international locations, including North America (Canada, the United States and Mexico), South America (Peru, Chile and Uruguay), and EMEA (Spain, Algeria and South Africa), and we may expand our operations to certain core countries within these regions. Accordingly, we face several risks associated with operating and investing in different countries that may have a material adverse effect on our business, financial condition, results of operations and cash flows. These risks include, but are not limited to, adapting to the regulatory requirements of such countries, compliance with changes in laws and regulations applicable to foreign corporations, the uncertainty of judicial processes, and the absence, loss or non-renewal of favorable treaties, or similar agreements, with local authorities, or political, social and economic instability, all of which can place disproportionate demands on our management, as well as significant demands on our operational and financial personnel and business. As a result, we can provide no assurance that our future international operations and investments will remain profitable.
 
A significant portion of our current and potential future operations and investments are conducted in various emerging countries worldwide. Our activities and investments in these countries involve a number of risks that are more prevalent than in developed markets, such as economic and governmental instability, the possibility of significant amendments to, or changes in, the application of governmental regulations, the nationalization and expropriation of private property, payment collection difficulties, social unrest or protests, substantial fluctuations in interest and exchange rates, changes in the tax framework or the unpredictability of enforcement of contractual provisions, currency control measures, limits on the repatriation of funds and other unfavorable interventions or restrictions imposed by public authorities. In countries such as Mexico political changes could generate changes in regulation which could affect our business. Likewise, in countries such as Algeria or South Africa, a change in government can cause instability in the country and a new government may decide to change laws and regulations affecting our assets or may decide to expropriate such assets, all of which may have a material adverse effect on our business, financial condition, results of operations and cash flows. For example, in Chile violent social protests took place mainly between October 2019 and February 2020. Several social measures were approved. Protests could have an adverse effect on our business, financial condition, results of operations and cash flows. In addition, potential social measures could also have an adverse effect in our business, for example, if the government decided to increase taxation on our assets.
 
Our U.S. dollar-denominated contracts in several assets are payable in local currency at the exchange rate of the payment date and in some cases include portions in local currency. Likewise, our contract for Kaxu in South Africa is denominated and payable in South African rands. In the event of a rapid devaluation or implementation of exchange or currency controls, we may not be able to exchange the local currency for the agreed dollar amount, which could affect our cash available for distribution. Governments in Latin America and Africa frequently intervene their economies and occasionally make significant changes in policy and regulations. Governmental actions aimed to control inflation and other similar policies and regulations have often involved, among other measures, price controls, currency devaluations, capital or exchange controls and limits on imports. Such devaluation, implementation of exchange or currency controls or governmental involvement may have a material adverse effect on our business, financial condition, results of operations and cash flows.
 
We are exposed to political, social and macroeconomic risks relating to the United Kingdom’s exit from the European Union.
 
On January 31, 2020, the U.K. ceased to be part of the European Union and entered into a transition period to, among other things, negotiate an agreement with the EU on the future terms of the United Kingdom’s relationship with the European Union. On December 24, 2020, both parties announced that a trade agreement had been reached (the “Trade Agreement”), which was passed by both houses of the British parliament on December 30 and given Royal Assent on December 31, 2020, which ended the transition period.
 
On January 1, 2021, the U.K. left the EU Single Market and Customs Union, as well as all EU policies and international agreements. As a result,, the free movement of persons, goods, services and capital between the U.K. and the EU ended, with the EU and the U.K. forming two separate markets and two distinct regulatory and legal frameworks. The Trade Agreement offers U.K. and EU companies preferential access to each other’s markets, ensuring imported goods will be free of tariffs and quotas; however, economic relations between the U.K. and the EU will now be on more restricted terms than existed previously. Moreover, the Trade Agreement does not incorporate the full scope of the services sector, and certain businesses such as banking and finance face a more uncertain future. At this time, we cannot predict the impact that the Trade Agreement and any future agreements between the U.K. and the EU will have on our business. We continue to evaluate our own risks and uncertainty related to Brexit to better navigate the changes in the U.K.-EU market. The terms of the Trade Agreement once implemented, and other possible terms we cannot anticipate, could adversely affect our business, financial condition, results of operations and cash flows.
 

VII.
Risks Related to Regulation
 
We are subject to extensive governmental regulation in a number of different jurisdictions, and our inability to comply with existing regulations or requirements or changes in applicable regulations or requirements may have a negative impact on our business, financial condition, results of operations and cash flows.
 
We are subject to extensive regulation of our business in the countries in which we operate. Such laws and regulations require licenses, permits and other approvals to be obtained in connection with the operations of our activities. This regulatory framework imposes significant actual, day-to-day compliance burdens, costs and risks on us. In particular, the power plants and transmission lines that we own are subject to strict international, national, state and local regulations relating to their operation and expansion (including, among other things, leasing and use of land, and corresponding building permits, landscape conservation, noise regulation, environmental protection and environmental permits and electric transmission and distribution network congestion regulations). Non-compliance with such regulations could result in reputational damage, the revocation of permits, sanctions, fines, criminal penalties or lower our ESG ratings. Compliance with regulatory requirements may result in substantial costs to our operations that may not be recovered. In addition, we cannot predict the timing or form of any future regulatory or law enforcement initiatives. Changes in existing energy, environmental and administrative laws and regulations may have a material adverse effect on our business, financial condition, results of operations and cash flows, including on our growth plan and investment strategy. Our business may also be affected by additional taxes imposed on our activities, reduction of regulated tariffs and other cuts or measures.
 
Further, similar changes in laws and regulations could increase the size and number of claims and damages asserted against us or subject us to enforcement actions, fines and even criminal penalties. In addition, changes in laws and regulations may, in certain cases, have retroactive effect and may cause the result of operations to be lower than expected. In particular, our activities in the energy sector are subject to regulations applicable to the economic regime of generation of electricity from renewable sources and to subsidies or public support in the benefit of our production of energy from renewable energy sources, which vary by jurisdiction, and are subject to modifications that may be more restrictive or unfavorable to us.
 
Our business is subject to stringent environmental regulation.
 
We are subject to significant environmental regulation, which, among other things, requires us to obtain and maintain regulatory licenses, permits and other approvals and comply with the requirements of such licenses, permits and other approvals and perform environmental impact studies on changes to projects. In addition, our assets need to comply with strict environmental regulation on air emissions, water usage and contaminating spills, among others. As a company with a focus on ESG and most of the business in renewable energy, environmental incidents can also significantly harm our reputation. There can be no assurance that:
 

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

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

governmental authorities will approve our environmental impact studies where required to implement proposed changes to operational projects.
 
We believe that we are currently in material compliance with all applicable regulations, including those governing the environment. In the past, we have experienced some environmental accidents and we have been found not to be in compliance with certain environmental regulations and have incurred fines and penalties associated with such violations which, to date, have not been material in amount. We can give no assurance, however, that we will continue to be in compliance or avoid material fines, penalties, sanctions and expenses associated with compliance issues in the future. Violation of such regulations may give rise to significant liability, including fines, damages, fees and expenses, and site closures. Generally, relevant governmental authorities are empowered to clean up and remediate releases of environmental damage and to charge the costs of such remediation and clean-up to the owners or occupiers of the property, the persons responsible for the release and environmental damage, the producer of the contaminant and other parties, or to direct the responsible parties to take such action. These governmental authorities may also impose a tax or other liens on the responsible parties to secure the parties’ reimbursement obligations.
 
Environmental regulation has changed rapidly in recent years, and it is possible that we will be subject to even more stringent environmental standards in the future, including in relation to climate change. We cannot predict the amounts of any increased capital expenditures or any increases in operating costs or other expenses that we may incur to comply with applicable environmental, or other regulatory, requirements, or whether these costs can be passed on to its concession contract counterparties through price increases. The costs of compliance as well as non-compliance may have a material adverse effect on our business, financial condition, results of operations and cash flows.
 
Government regulations could change at any time and such changes may negatively impact our current business and our growth strategy.
 
In some of our assets such as the Spanish solar plants and one of our transmission lines in Chile, revenues are based on existing regulation. We may also acquire in the future additional assets or businesses with regulated revenues. For these types of assets and businesses, if regulation changes, it may have a material adverse effect on our business, financial condition, results of operations and cash flows.
 
In addition, our strategy to grow our business through the acquisition of renewable energy projects partly depends on current government policies that promote and support renewable energy and enhance the economic viability of owning solar and wind energy projects. Renewable energy projects currently benefit from various U.S. federal, state and local governmental incentives, such as ITCs, PTCs, loan guarantees, RPS programs, or MACRS along with other incentives. These incentives make the development of renewable energy projects more competitive by providing tax credits, accelerated depreciation and expensing for a portion of the development costs, decreasing the costs associated with developing such projects or creating demand for renewable energy assets through RPS programs. These policies have had a significant impact on the development of renewable energy, and they could change at any time. Additionally, many of these government incentives, including the ITCs and the PTCs, are subject to phase-out and/or expiration. A loss or reduction in such incentives or the value of such incentives, a change in policy away from limitations on coal and gas electric generation, mining and exploration, or a reduction in the capacity of potential investors to benefit from such incentives could decrease the attractiveness of solar or renewable energy projects to project developers, and the attractiveness of solar energy systems to utilities, retailers and customers. A reduction or removal of incentives may diminish the market for future renewable energy off-take agreements and reduce the ability for renewable developers to compete for future energy off-take agreements, which may reduce incentives for project developers to invest in the development and construction of clean energy and water infrastructure contracted assets. This could cause reduced economic returns, resulting in increased financing costs and difficulty in obtaining financing. Such a loss or reduction could also reduce our acquisition opportunities and our willingness to pursue renewable energy projects due to higher operating costs or lower revenues from off-take agreements. See also “—Risks Related to Taxation.”
 
Additionally, some U.S. states with RPS targets have met, or in the near future will meet, their renewable energy targets. For example, California, which has among the most aggressive RPS laws in the United States, is poised to meet its current mandate of 33.0% renewable energy by 2020 with already-proposed new renewable energy projects, though significant additional investments will be required to meet the higher renewable energy mandate of 60.0% by 2030 and 100% by 2045 that was adopted in 2018. If, as a result of achieving these targets, these and other U.S. states do not increase their targets in the near future, demand for additional renewable energy could decrease. In addition, the substantial increase of grid connected intermittent solar and wind generation assets resulting from the adoption of RPS targets has created significant technical challenges for grid operators. As a result, RPS targets may need to be scaled back or delayed in order to develop technologies or infrastructure to accommodate this increase in intermittent generation assets.
 
We rely, in a significant part, on environmental and other regulations of industrial and local government activities, including regulations mandating, among other things, reductions in carbon or other greenhouse gas emissions or use of energy from renewable sources. If the businesses to which such regulations relate were deregulated or if such regulations were materially changed or weakened, the profitability of our current and future projects could suffer, which could in turn have a material adverse effect on our business, financial condition, results of operations and cash flows. In addition, uncertainty regarding possible changes to any such regulations has adversely affected us in the past, and may adversely affect in the future, our ability to refinance a project or to satisfy other financing needs.
 
Subsidy regimes for renewable energy generation have been challenged in the past on constitutional and other grounds (including that such regimes constitute impermissible European Union state aid) in certain jurisdictions. In addition, certain loan-guarantee programs in the United States, including those which have enabled the DOE to provide loan guarantees to support our Solana and Mojave projects in the United States, have been challenged on grounds of failure by the appropriate authorities to comply with applicable U.S. federal administrative and energy law. If all or part of the subsidy and incentive regimes for renewable energy generation in any jurisdiction in which we operate were found to be unlawful and, therefore, reduced or discontinued, we may be unable to compete effectively with conventional and other renewable forms of energy. We currently have two financing arrangements with the Federal Financing Bank for the Solana and Mojave assets, repayment of which to the Federal Financing Bank by those projects is with a guarantee by the DOE. Additionally, these projects benefit from the ITCs. Unilateral changes to these agreements or the ITC regime may have a material adverse effect on our business, financial condition, results of operations and cash flows.
 
In addition, there are some proposed changes in regulation in Mexico. On February 1st, 2021, Mexico´s President proposed a preferential reform to the Electricity Industry Act, meaning that the Congress shall vote on it no later than April 30th. The reform proposes several measures aimed at increasing preponderance of the CFE in different areas. Although we do not expect a direct impact on our existing contracts, we cannot guarantee that the new regulation will not have any impact on our business, financial condition, results of operations and cash flows. The new regulation could also limit our growth prospects in the region. Additionally, there is a proposed change in regulation on sub-contracting activities. We cannot guarantee that we will not have a negative impact on our business, financial condition, results of operations and cash flows.
 
Revenues in our solar assets in Spain are mainly defined by regulation and some of the parameters defining the remuneration are subject to review every six years. Revenues in Chile TL3 are also mainly defined by regulation.
 
According to Royal Decree 413/2014, solar electricity producers in Spain receive: (i) the pool price for the power they produce, (ii) a payment based on the standard investment cost for each type of plant (without any relation whatsoever to the amount of power they generate) and (iii) an “operating payment” (in €/MWh produced).
 
The principle driving this economic regime is that the payments received by a renewable energy producer should be equivalent to the costs that they are unable to recover on the electricity pool market where they compete with non-renewable technologies. This economic regime seeks to allow a “well-run and efficient enterprise” to recover the costs of building and running a plant, plus a reasonable return on investment (project investment rate of return). The rate applicable during the first regulatory period was 7.398%.
 
On July 27, 2018, CNMC (the regulator for the electricity system in Spain) issued a draft proposal for the calculation of the reasonable rate of return for the regulatory period 2020-2025. On November 2, 2018, CNMC issued its final report with a proposed reasonable rate of return of 7.09%. In December 2018 the government issued a draft project law proposing a reasonable rate of return of 7.09%, with the possibility of maintaining the 7.398% reasonable rate of return under certain circumstances. On November 24, 2019, the Spanish government approved Royal Decree-law 17/2019 setting out a 7.09% rate of reasonable return applicable from January 1, 2020 until December 31, 2025 as a general rule and the possibility, under certain circumstances including not having any ongoing legal proceeding against the Kingdom of Spain ongoing, of maintaining the 7.398% reasonable rate of return for two consecutive regulatory periods. The reasonable return was calculated by reference to the weighted average cost of capital (WACC), the calculation method that most of the European regulators apply to determine the return rates applicable to regulated activities within the energy sector. As a result, some of the assets in our Spanish portfolio are receiving a remuneration based on a 7.09% reasonable rate of return until December 31, 2025 while others are receiving a remuneration based on a 7.398% reasonable rate of return until December 31, 2031.
 
If the payments for renewable energy plants are revised to lower amounts in the next regulatory period starting on January 1, 2026 until December 31, 2031 or starting on January 1, 2032, depending on each asset, this could have a material adverse effect on our business, financial condition, results of operations and cash flows. As a reference, assuming our Spanish assets continue to perform as expected and assuming no additional changes of circumstances, with the information currently available, Atlantica estimates that a reduction of 100 basis points in the reasonable rate of return on investment set by the Spanish government could cause a reduction in its cash available for distribution of approximately €18 million per year. This estimate is subject to certain assumptions, which may change in the future.
 
Our international operations require us to comply with anti-corruption and other laws and regulations of the United States government and various non-U.S. jurisdictions.
 
Doing business in multiple countries requires us and our subsidiaries to comply with the laws and regulations of the United States government and various non-U.S. jurisdictions. Our failure to comply with these rules and regulations may expose us to liabilities. These laws and regulations may apply to us, our subsidiaries, individual directors, officers, employees and agents, and may restrict our operations, trade practices, investment decisions and partnering activities.
 
In particular, our non-U.S. operations are subject to United States and foreign anti-corruption laws and regulations, such as the Foreign Corrupt Practices Act of 1977, as amended (“FCPA”), and similar laws and regulations. The FCPA prohibits United States companies and their officers, directors, employees and agents acting on their behalf from corruptly offering, promising, authorizing or providing anything of value to foreign officials for the purposes of influencing official decisions or obtaining or retaining business or otherwise obtaining favorable treatment. The FCPA also requires companies to make and keep books, records and accounts that accurately and fairly reflect transactions and dispositions of assets and to maintain a system of adequate internal accounting controls. As part of our business, we deal with state-owned business enterprises, the employees and representatives of which may be considered foreign officials for purposes of the FCPA. As a result, business dealings between our employees and any such foreign official could expose us to the risk of violating anti-corruption laws even if such business practices may be customary or are not otherwise prohibited between the us and a private third party. Violations of these legal requirements are punishable by criminal fines and imprisonment, civil penalties, disgorgement of profits, injunctions, debarment from government contracts as well as other remedial measures.
 
We have established policies and procedures designed to assist us and our personnel in complying with applicable United States and non-U.S. laws and regulations; however, we cannot assure you that these policies and procedures will completely eliminate the risk of a violation of these legal requirements, and any such violation (inadvertent or otherwise) could have a material adverse effect on our business, financial condition, results of operations and cash flows.
 

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

operational performance of our assets;

potential capital expenditure requirements in our assets in the case there were technical problems environmental or regulatory requirements not covered by the EPC contractor guarantee or O&M contractor guarantee or by insurance;

our debt service requirements and other liabilities;

fluctuations in our working capital needs;

fluctuations in foreign exchange rates;

the level of our operating and general and administrative expenses,

seasonal variations in revenues generated by the business;

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

our ability to borrow funds, including intercompany loans;

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

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

other business risks affecting our cash levels.
 
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 may incur other expenses or liabilities during a period that could significantly reduce or eliminate our cash available for distribution and, in turn, impair our ability to pay dividends to shareholders during the period.
 
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.
 
 Because we are a holding company, our ability to pay dividends on our shares is limited by restrictions under the Revolving Credit Facility, the Note Issuance Facility 2019, the Green Private Placement and the Note Issuance Facility 2020 or 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, any of which could change from time to time and thereby limit our subsidiaries’ ability to pay dividends or make other distributions to us.
 
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 for which the cash distributions we would otherwise receive from our subsidiary project companies would otherwise be insufficient to pay our quarterly dividend. 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 sales of our shares by Algonquin or its lenders or by other substantial shareholders may cause the price of our shares to fall.
 
The market price of our shares could decline as a result of future sales by Algonquin of its shares in the market, or the perception that these sales could occur. Algonquin is the beneficial owner of approximately 44.2% of our ordinary shares. On November 28, 2018, AAGES obtained a secured credit facility in the amount of $306,500,000. The AAGES secured credit facility is collateralized through a pledge of the Atlantica shares held by a company participated by Algonquin. A collateral shortfall would occur if the net obligation as defined in the agreement would equal or exceed 50% of the market value of the Atlantica shares in which case the AAGES Credit Facility lenders would have the right to sell Atlantica shares to eliminate the collateral shortfall.
 
If AAGES defaulted on any of these financing arrangements, its lenders may foreclose on the shares and sell the shares in the market. Future sales of substantial amounts of the shares and/or equity-related securities in the public market, or the perception that such sales could occur, could adversely affect prevailing trading prices of the shares and could impair our ability to raise capital through future offerings of equity or equity-related securities. The price of the shares could be depressed by investors’ anticipation of the potential sale in the market of substantial additional amounts of shares. Disposals of shares could increase the number of shares being offered for sale in the market and depress the trading price of our shares.
 
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 English law. The rights of holders of our shares are governed by English law, 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. Most of our officers and directors reside outside of the United States. In addition, a portion of our assets and the majority of the assets of our directors and officers are located outside the United States. As a result, it may be difficult or impossible to serve legal process on persons located outside the United States and to force 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, 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. Because we are a foreign private issuer, our directors and officers will not be subject to rules under the Exchange Act that under certain circumstances would require directors and officers to forfeit to us any “short-swing” profits realized from purchases and sales, as determined under the Exchange Act and the rules thereunder, of our equity securities. 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, AAGES or Algonquin or both of them 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 the AAGES or Algonquin ROFO Agreement; and (ii) up to 66.0% of our ordinary shares if the purpose of the issuance is to fund our acquisition of assets under the Abengoa ROFO Agreement. If we issue ordinary shares for any other purpose, AAGES or Algonquin may subscribe in cash for our ordinary shares in a pro rata amount of such AAGES’ or Algonquin’s aggregate holding of voting rights in us. The Shareholders Agreement may be terminated or modified in the future.
 
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 United Kingdom and whose securities are not admitted to trading on a regulated market in the United Kingdom 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 United Kingdom. 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 United Kingdom, we would be subject to a number of rules and restrictions, including but not limited to the following: (1) our ability to enter into deal protection arrangements with a bidder would be extremely limited; (2) we may not, without the approval of our shareholders, be able to perform certain actions that could have the effect of frustrating an offer, such as issuing shares or carrying out acquisitions or disposals; and (3) we would be obliged to provide equality of information to all bona fide competing bidders.
 

IX.
Risks Related to Taxation
 
Changes in our tax position can significantly affect our reported earnings and cash flows.
 
We have assets in different jurisdictions, which are subject to different tax regimes. Changes in tax regimes such as the reduction or elimination of tax benefits, or the reduction of tax rates overall in markets where we operate could adversely affect the market for investments in our projects by third parties. 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. Limitations on the deductibility of interest expense could reduce our ability to deduct the interest we pay on our debt. These and other potential changes in tax regulations could have a material adverse effect on our results and cash flows.
 
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. 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.
 
On December 31, 2020, the congress of Spain approved the General Budget Law for 2021. The new Law has introduced new limitations in certain incentives and deductions of the Corporate Income Tax for 2021 onwards. The most relevant modification contemplates a reduction in the tax exemption on dividends and capital gains received from affiliates from 100% to 95%. Despite the new limitation, we do not expect a significant impact in cash flows from our Spanish solar assets in the upcoming years.
 
On June 29, 2020, California’s Governor signed AB 85, suspending California Net Operating Losses (“NOL”) utilization and imposing a cap on the amount of business incentive tax credits companies can utilize, effective for tax years 2020, 2021 and 2022. During these years, Mojave will not be able to use its NOLs to offset its state tax, which is set at approximately 8.9%. The years 2020 to 2022 will not be considered in the calculation of NOLs expiration, resulting in a suspension rather than a cancellation or shortening of the period of utilization of such NOLs. We expect to utilize the accumulated NOLs from 2022 onwards. However, we expect AB 85 will have a negative impact, which we estimate in the range of $6 to $7 million per year in distributions expected from Mojave from 2021 to 2023.
 
In addition, some countries where we operate, including the U.S. and South Africa, could implement tax reforms the content of which is largely unknown currently. These potential tax reforms 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 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.
 
Our future tax liability may be greater than expected if we do not use sufficient NOLs to offset our taxable income.
 
We have NOLs that we can use to offset future taxable income. Based on our current portfolio of assets, which include renewable assets that benefit from an accelerated tax depreciation schedule, and subject to potential tax audits, which may result in income, sales, use or other tax obligations, we do not expect to pay significant taxes in the upcoming years.
 
Although we expect these NOLs will be available as a future benefit, in the event that they are not generated as expected, or are successfully challenged by the local tax authorities, such as the IRS or Her Majesty’s Revenue and Customs among others, by way of a tax audit or otherwise, or are subject to future limitations as discussed below, our ability to realize these benefits may be limited. A reduction in our expected NOLs, a limitation on our ability to use such NOLs or the occurrence of future tax audits may result in a material increase in our estimated future income tax liability and may have a material adverse effect on our business, financial condition, results of operations and cash flows.
 
Our ability to use U.S. NOLs to offset future income may be limited.
 
We have generated significant NOLs. For purposes of U.S. federal income taxation, NOLs generated on or before December 31, 2017 can generally be carried back two years and carried forward for up to twenty years and can be applied to offset 100% of taxable income in such years. As a result of the CARES Act, NOLs incurred between January 1, 2018 and December 31, 2020 may be carried forward indefinitely and carried back five years. Losses arising after December 31, 2020, cannot be carried back and are subject to limitations on their deductibility that may prevent us from using the NOLs to offset all taxable income in future years.
 
In addition, our ability to use U.S. NOLs generated is subject to the rules of Sections 382 of the IRC. This section generally restricts the use of U.S. NOLs if we were to experience an “ownership change” as defined under Section 382 of the IRC, and similar state rules. In general, an “ownership change” would occur if our “5-percent shareholders,” as defined under Section 382 of the IRC, collectively increased their ownership in us to more than 50 percentage points over a rolling three-year period. A corporation that experiences an ownership change will generally be subject to an annual limitation on the use of its pre-ownership change U.S. NOLs equal to the equity value of the corporation immediately before the ownership change, multiplied by the long-term tax-exempt rate for the month in which the ownership change occurs, and increased by a certain portion of any “built-in-gains.”
 
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 addition, changes in our shareholder base during 2019 may have triggered an ownership change under Section 382 of the IRC. In addition, the Internal Revenue Service recently issued proposed regulations for the calculation of built-in gains and losses under Section 382. If enacted and depending on its final outcome, this new regulation 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.
 
Distributions to U.S. Holders of our shares may be fully taxable as dividends.
 
It is difficult to predict whether or to what extent we will generate earnings or profits as computed for U.S. federal income tax purposes in any given tax year. If we make distributions on the shares from current or accumulated earnings and profits as computed for U.S. federal income tax purposes, such distributions generally will be taxable to U.S. Holders of our shares as ordinary dividend income for U.S. federal income tax purposes. Under current law, if certain requirements are met, such dividends would be eligible for the lower tax rates applicable to qualified dividend income of certain non-corporate U.S. Holders. While we expect that a portion of our distributions to U.S. Holders of our shares may exceed our current and accumulated earnings and profits as computed for U.S. federal income tax purposes, and therefore may constitute a non-taxable return of capital to the extent of a U.S. Holder’s basis in our shares, no assurance can be given that this will occur. We intend to calculate our earnings and profits annually in accordance with U.S. federal income tax principles. See “Item 10.E—Taxation—Material U.S. Federal Income Tax Considerations.”
 
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 2019 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. However, 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—Material U.S. Federal Income Tax Considerations—Passive foreign investment company rules.”
 

X.
General Risk Factors
 
The loss of one or more of our executive officers or key employees may adversely affect our ability to effectively manage our projects.
 
We depend on our experienced management team and the loss of one or more key executives may negatively affect our business. We also depend on our ability to retain and motivate key employees and attract qualified new employees. We may not be able to replace departing members of our management team or key employees. Integrating new executives into our management team and training new employees with no prior experience in our industry could prove disruptive to our projects, require a disproportionate amount of resources and management attention and ultimately prove unsuccessful. An inability to attract and retain sufficient technical and managerial personnel could limit our ability to effectively manage our projects, which could have a material adverse effect on our business, financial condition, results of operations and cash flows.
 
ITEM 4
INFORMATION ON THE COMPANY

A.
History and Development of the Company

We are a sustainable infrastructure company that owns and manages renewable energy, storage, efficient natural gas, transmission and transportation infrastructure and water assets. We currently have operating facilities in North America (United States, Canada and Mexico), South America (Peru, Chile and Uruguay) and EMEA (Spain, Algeria and South Africa). Our portfolio consists of 28 assets with 1,591 MW of aggregate renewable energy installed generation capacity (of which approximately 90% is solar), 343 MW of efficient natural gas-fired power generation capacity, 1,166 miles of electric transmission lines and 17.5 M ft3 per day of water desalination. In 2020, our renewable sector represented approximately 74% of our revenue with solar energy representing approximately 70%.

We were incorporated in England and Wales as a private limited company on December 17, 2013. On June 18, 2014, we completed our IPO and our shares are listed on the NASDAQ Global Select Market under the symbol “AY.” The address of our principal executive offices is Great West House, GW1, 17th floor, Great West Road, Brentford, TW8 9DF, United Kingdom, and our phone number is +44 203 499 0465. Our current agent in the U.S. is ASHUSA, Inc., a Delaware company with its principal office located at 1553 W. Todd Drive, Suite 204, Tempe, Arizona 85283, 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 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%.

Acquisitions

Historical acquisitions

Following our IPO in 2014, we completed a series of four dropdown asset acquisitions with Abengoa including Solacor 1 & 2, PS 10 & 20, Cadonal, Honaine, Skikda, Helioenergy 1 & 2, Helios 1 & 2, Solnova 1, 3 & 4, Kaxu, ATN2 and Solaben 1 & 6. In 2016 and 2017, we acquired a stake in a transmission line in the United States from Abengoa and in Seville PV. In 2018, we acquired Mini-Hydro, ATN Expansion 1, Chile TL3 and Melowind from third parties. See “—Business Overview—Our Operations”.

2019 acquisitions

In January 2019, we entered into an agreement with Abengoa under the Abengoa ROFO Agreement for the acquisition of Tenes and paid $19.9 million as an advance payment. Closing of the acquisition was subject to certain conditions precedent, which were not fulfilled. In accordance with the terms of the share purchase agreement, the advance payment was converted into 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. In October 2019, we received a first payment of $7.8 million through the cash sweep mechanism. On May 31, 2020, we entered into a new $4.5 million secured loan agreement with Befesa Agua Tenes. This new loan is expected to be reimbursed no later than May 31, 2032, together with 12% interest per annum, through a full cash-sweep of all the dividends to be received from the asset. In addition, the new agreement provides us with certain additional decision rights, a call option over the shares of Befesa Agua Tenes at a price of $1 and a majority at the Board of Directors of Befesa Agua Tenes. Therefore, we have concluded that we have had control over Tenes since May 31, 2020 and as a result we have fully consolidated the asset from that date.

On May 31, 2019, we entered into an agreement with Abengoa to acquire a 15% stake in Rioglass, a multinational manufacturer of solar components in order to secure certain Abengoa obligations. The investment was $7 million and is classified as held for sale.

On August 2, 2019 we acquired a 30% stake in Monterrey, a 142 MW gas-fired engine facility including 130 MW installed capacity and 12 MW battery capacity. We paid $42 million for the total equity investment. The asset, located in Mexico, has been in operation since 2018 and represents our first investment in electric batteries. It has a U.S. dollar-denominated 20-year PPA with two international large corporations engaged in the car manufacturing industry as well as a 20-year contract for the natural gas transportation from Texas with a U.S. energy company. The PPA also includes price escalation factors. The asset has no commodity risk and may have the possibility to sell excess energy to the North-East region of the country. We also entered into a ROFO agreement with the seller of the shares for the remaining 70% stake in the asset.

On August 2, 2019, we closed the acquisition of ASI Operations, the company that performs the operation and maintenance services to Solana and Mojave plants. The consideration paid was $6 million.

In October 2019, we closed the acquisition of ATN Expansion 2, for a total equity investment of approximately $20 million. The off-taker is Enel Green Power Peru.

2020 and 2021 acquisitions

On April 3, 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. The first investment was the acquisition of a 55 MW solar PV plant in an area with excellent solar resource (Chile PV 1). This asset, has been in operation since 2016, demonstrating a good operating track record during that period while selling its production to the Chilean power market. Our initial contribution was approximately $4 million. On January 6, 2021 we also closed our second investment through the platform with the acquisition of Chile PV 2, a 40 MW PV plant. This asset started commercial operation in 2017 and its revenue is partially contracted. Total equity investment in this new asset was approximately $5.0 million. We have concluded that we have control over these assets, and we are fully consolidating it since each acquisition date. The platform intends to make further investments in renewable energy in Chile and sign PPAs with creditworthy off-takers.

On August 17, 2020 we closed the acquisition of the Liberty ownership interest in Solana. Liberty was the tax equity investor in Solana. Total equity investment is expected to be up to $290 million of which $272 million has already been paid. The total price includes a deferred payment and a performance earn-out based on the average annual net production of the asset in the four calendar years with the highest annual net production during the five calendar years of 2020 through 2024.

In October 2020 we reached an agreement to acquire Calgary District Heating, a district heating asset in Canada for a total equity investment of approximately $20 million. Calgary District Heating has been in operation since 2010 and represents our first investment in this sector, a sector which has been recognized by the UN Environment Program as being a key measure for cities to reduce their emissions. The asset provides heating services to a diverse range of government, institutional and commercial customers in the city of Calgary. It has availability-based revenue with inflation indexation and 20 years of weighted average contract life. Contracted capacity and volume payments represent approximately 80% of the total revenue. Closing is expected by mid-2021 subject to customary conditions precedent and regulatory approvals.

In December 2020 we reached an agreement with Algonquin to acquire La Sierpe, a 20 MW solar asset in Colombia for a total equity investment of approximately $20 million. Closing is expected to occur after the asset reaches commercial operation, currently expected to occur by mid-2021. Closing is subject to customary conditions precedent and regulatory approvals. Additionally, we agreed to potentially co-invest with Algonquin in additional solar plants in Colombia with a combined capacity of approximately 30 MW to be developed and built by AAGES.

In December 2020, we reached an agreement to acquire 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 ISO. It has PPAs signed with three investment grade offtakers, with a 19-year average contract life. Closing is subject to customary regulatory approvals and is expected to occur in the first half of 2021. The total investment is expected to be approximately $170 million, including approximately $130 million for the equity and $40 million expected to be invested in reducing project debt.

In January 2021 we reached an agreement to increase our equity stake from 15% up to 100% in Rioglass, a multinational manufacturer of solar components. We have closed the acquisition of 42.5% equity stake, for which we paid $7 million. In addition, we have an option to acquire the remaining 42.5% in the same conditions until September 2021, and after that date the seller has an option to sell the 42.5% also in the same conditions. We intend to find partners to co-invest in the company, as such we expect to classify the investment as held for sale in our consolidated financial statements.

In October 2018, we reached an agreement to acquire PTS, a natural gas transportation platform located in Mexico, close to ACT. PTS has a service agreement signed in October 2017, which is a “take-or-pay” 11-year term contract starting in 2020. We initially acquired a 5% ownership in the project and have an agreement to acquire an additional 65% stake subject to the asset entering into commercial operation, non-recourse project financing being closed and final approvals and customary conditions, including the absence of material adverse effects. Our partner in this asset is also negotiating to sell part of its business, which may include the company that provides operation and maintenance services to PTS. This sale may require change of control waivers and may make the closing of the acquisition more difficult. Additionally, our partner has proposed a number of modifications to the project and in the financing agreements. We are currently monitoring the situation in order to decide if we will proceed with the investment or not. We therefore cannot guarantee that we will close this acquisition or that closing will occur on the terms originally agreed.

B.
Business Overview

Overview

We are a sustainable infrastructure company with a majority of our business in renewable energy assets. In 2020, our renewable sector represented approximately 74% of our revenue with solar energy representing approximately 70%. 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 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.

As of the date of this annual report, we own or have an interest in a portfolio of diversified assets in terms of business sector and geographic footprint. Our portfolio consists of 28 assets with 1,591 MW of aggregate renewable energy installed generation capacity (of which approximately 90% is solar), representing 74.3% out of our total revenue, 343 MW of efficient natural gas-fired power generation capacity, 1,166 miles of electric transmission lines and 17.5 M ft3 per day of water desalination.

We currently own and manage operating facilities in North America (United States, Canada and Mexico), South America (Peru, Chile, and Uruguay) and EMEA (Spain, Algeria and South Africa). We intend to expand our portfolio, while maintaining North America, South America and Europe as our core geographies.

Our assets generally have contracted revenue (regulated revenue in the case of our Spanish assets and one transmission line in Chile). We focus on long-life facilities as well as long-term agreements that we expect to produce stable, long-term cash flows. As of December 31, 2020, our assets had a weighted average remaining contract life of approximately 17 years. Most of the assets we own, or which we hold an interest in have project-finance agreements in place. We intend to grow our cash available for distribution and our dividend to shareholders through organic growth and by acquiring new assets and/or businesses where revenue may not be fully contracted.

We intend to take advantage of, and leverage our growth strategy on, favorable trends in clean power generation, energy scarcity and the focus on the reduction of carbon emissions. Our portfolio of operating assets and our strategy focus on sustainable technology including renewable energy, storage, efficient natural gas, and transmission networks as enablers of a sustainable power generation mix and on water infrastructure. Renewable energy is expected to represent, in most markets, the majority of new investments in the power sector, according to Bloomberg New Energy Finance 2020. Approximately 68% of the world’s power generation by 2050 is expected to come from renewable energy sources, which indicates that renewable energy is becoming mainstream. Global installed capacity is expected to shift from 56% fossil fuels today to approximately two-thirds renewables by 2050. A 14-terawatt expansion of generating capacity is estimated to require approximately $15.1 trillion of new investment between now and 2050 – of which approximately 73% is expected to go to renewables. Another approximately $1 trillion of investment is expected in batteries along with an estimated $14 trillion expected to go to transmission and distribution during that same period. Regions will need to complement investments in renewable energy with investments in storage, efficient natural gas and in transmission networks. Atlantica is well positioned to benefit from the expected transition towards a more sustainable power generation mix. In addition, we believe that water is going to be the next frontier in a transition towards a more sustainable world. New sources of water are needed worldwide, and thus water desalination and transportation infrastructure should help make that possible. We currently participate in three water desalination plants with a total capacity of 17.5 million cubic feet per day.

We believe we can achieve organic growth through the optimization of the existing portfolio, escalation factors at many of our assets and the expansion of current assets, particularly our transmission lines, to which new assets can be connected. We currently own three transmission lines in Peru and four in Chile. We believe that current regulations in Peru and Chile should provide an opportunity for growth via the expansion of transmission lines to connect new clients. Additionally, we should have repowering opportunities in certain existing renewable energy assets.

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 have also entered into and intend to enter into agreements or partnerships with developers and asset owners to acquire assets. We also invest directly and through investment vehicles with partners in assets under development or construction.

We have signed a ROFO agreement with AAGES, a joint venture designed to invest in the development and construction of contracted clean energy and water infrastructure contracted assets, created by Algonquin, a North American diversified generation, transmission and distribution utility company that owns a 44.2% stake in our capital stock.

With this business model, 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 and through the acquisition of assets. Pursuant to our cash dividend policy, we intend to pay a cash dividend each quarter to holders of our shares.

Current Operations

Our assets are organized into the following four business sectors: Renewable Energy, Efficient Natural Gas, Electric Transmission 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
Left(14)
                 
Solana
Renewable
(Solar)
100%
Arizona
(USA)
USD
280 MW
A-/A2/A-
2013
23
Mojave
Renewable
(Solar)
100%
California
(USA)
USD
280 MW
BB-/WR/BB
2014
19
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
N/A
2017
N/A
Solaben 2 & 3
Renewable
(Solar)
70%(1)
Spain
Euro
2x50 MW
A/Baa1/A-
2012
17/17
Solacor 1 & 2
Renewable
(Solar)
87%(2)
Spain
Euro
2x50 MW
A/Baa1/A-
2012
16/16
PS10 & PS20
Renewable
(Solar)
100%
Spain
Euro
31 MW
A/Baa1/A-
2007&
2009
11/13
Helioenergy 1 & 2
Renewable
(Solar)
100%
Spain
Euro
2x50 MW
A/Baa1/A-
2011
16/16
Helios 1 & 2
Renewable
(Solar)
100%
Spain
Euro
2x50 MW
A/Baa1/A-
2012
16/17
Solnova 1, 3 & 4
Renewable
(Solar)
100%
Spain
Euro
3x50 MW
A/Baa1/A-
2010
14/14/15
Solaben 1 & 6
Renewable
(Solar)
100%
Spain
Euro
2x50 MW
A/Baa1/A-
2013
18/18
Seville PV
Renewable
(Solar)
80%(6)
Spain
Euro
1 MW
A/Baa1/A-
2006
15
Kaxu
Renewable
(Solar)
51%(3)
South
Africa
Rand
100 MW
BB/Ba2/
BB-(11)
2015
14
Palmatir
Renewable
(Wind)
100%
Uruguay
USD
50 MW
BBB/Baa2/BBB-(12)
2014
13
Cadonal
Renewable
(Wind)
100%
Uruguay
USD
50 MW
BBB/Baa2/BBB-(12)
2014
14
Melowind
Renewable
(Wind)
100%
Uruguay
USD
50 MW
BBB/Baa2/BBB-
2015
15
Mini-Hydro
Renewable
(Hydraulic)
100%
Peru
USD
4 MW
BBB+/A3/BBB+
2012
12
ACT
Efficient
natural gas
100%
Mexico
USD
300 MW
BBB/ Ba2/
BB-
2013
12
Monterrey
Efficient
natural gas
30%
Mexico
USD
142 MW
Not rated
2018
18
ATN (13)
Transmission
line
100%
Peru
USD
379 miles
BBB+/A3/BBB+
2011
20
ATS
Transmission
line
100%
Peru
USD
569 miles
BBB+/A3/BBB+
2014
23
ATN 2
Transmission
line
100%
Peru
USD
81 miles
Not rated
2015
12
Quadra 1 & 2
Transmission
line
100%
Chile
USD
49 miles/
32 miles
Not rated
2014
14/14
Palmucho
Transmission
line
100%
Chile
USD
6 miles
BBB+/Baa1/
A-
2007
17

Chile TL3
Transmission
line
100%
Chile
USD
50 miles
A+/A1/A-
1993
Regulated
Skikda
Water
34.2%(4)
Algeria
USD
3.5 M
ft3/day
Not rated
2009
13
Honaine
Water
25.5%(5)
Algeria
USD
7 M ft3/
day
Not rated
2012
17
Tenes
Water
51%(7)
Algeria
USD
7 M ft3/
day
Not rated
2015
19

Notes:
(1)
Itochu Corporation, a Japanese trading company, holds 30% of the shares in both Solaben 2 and Solaben 3.
(2)
JGC, a Japanese engineering company, holds 13% of the shares in each of Solacor 1 and Solacor 2.
(3)
Kaxu is owned by the Company (51%), Industrial Development Corporation of South Africa (29%) and Kaxu Community Trust (20%).
(4)
Algerian Energy Company, SPA owns 49% of Skikda and Sacyr Agua, S.L. owns the remaining 16.83%.
(5)
Algerian Energy Company, SPA owns 49% of Honaine and Sacyr Agua, S.L. owns the remaining 25.5%.
(6)
Instituto para la Diversificación y Ahorro de la Energía (“Idae”), a Spanish state-owned company, holds 20% of the shares in Seville PV.
(7)
Algerian Energy Company, SPA owns 49% of Tenes.
(8)
65% of the shares in Chile PV 1 and Chile PV 2 are held by financial partners at our renewable energy platform in Chile.
(9)
Certain contracts denominated in U.S. dollars are payable in local currency.
(10)
Reflects the counterparty’s credit ratings issued by Standard & Poor’s Ratings Services, or S&P, Moody’s Investors Service Inc., or Moody’s, and Fitch Ratings Ltd, or Fitch.
(11)
Refers to the credit rating of the Republic of South Africa. The offtaker is Eskom, which is a state-owned utility company in South Africa.
(12)
Refers to the credit rating of Uruguay, as UTE (Administración Nacional de Usinas y Transmisoras Eléctricas) is unrated.
(13)
Including the acquisition of ATN Expansion 1 & 2.
(14)
As of December 31, 2020.
(*)
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 that by investing in sustainable sectors and managing our assets in a sustainable manner we will create more value over time to our shareholders and to the rest of our stakeholders.

We manage and efficiently operate our portfolio of renewable energy, storage, efficient natural gas, transmission and transportation infrastructure and water assets to generate stable cash flows. Our assets generally have long-term contracts or regulation in place. We intend to distribute a stable cash dividend to our shareholders.

We seek to grow our cash available for distribution and our dividend to shareholders through organic growth and by investing in new assets, while ensuring the ongoing stability and sustainability of our business. We believe that our diversification by business sector and geography provides us with access to different sources of growth. We intend to grow our business maintaining renewable energy as our main segment and with a focus in North and South America.

We expect to deliver organic growth through the optimization of the existing portfolio and through investments in the expansion of our current assets, particularly in our transmission lines and renewable energy sectors. In addition, 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 have also entered into and intend to enter into agreements or partnerships with developers or asset owners to acquire assets. We also invest directly and through investment vehicles with partners in assets under development or construction. We also expect to acquire assets through our ROFO agreement with AAGES. AAGES is a development company created by Algonquin and designed to invest in the development and construction of contracted clean energy and contracted water infrastructure assets, with whom we have signed a ROFO agreement.

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

Focus on stable, long-term contracted or regulated assets in the power and water sectors, including renewable energy, storage, efficient natural gas generation, transmission and transportation infrastructure, district heating assets as well as water assets

We intend to focus on owning and operating stable, sustainable infrastructures, 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 expect this to allow us to maximize value and cash flow generation. 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 technologies will see significant growth in our targeted geographies.

Maintain diversification across three core geographic areas

Our focus on three core geographies, North America, South America and Europe, helps to ensure exposure to markets in which we believe the renewable energy, storage, efficient natural gas and transmission and transportation sectors will continue to grow significantly.

Increase cash available for distribution through the optimization of the existing portfolio and through the investments in the expansion of our current assets, particularly in our transmission lines, to which new assets can be connected and in our renewable energy assets.

We intend to grow our cash available for distribution to shareholders 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 of our current assets, particularly in our transmission lines and renewable energy assets.

We currently own three transmission lines in Peru and four in Chile. Current regulations in Peru and Chile provide growth opportunities via the expansion of transmission lines to connect new clients.

We have identified several opportunities to grow organically in Peru and Chile by expanding our existing assets. These opportunities consist of (i) new clients that need to use our assets, in situations where virtually no investment is required from us, while we will gain additional revenue from these new business opportunities and (ii) expansion of existing transmission lines to grant access to new clients. In this case, certain investments are required to build new assets that enable new clients to connect to our current backbone transmission lines. We would expect that in some cases these new assets would become part of our concession asset contracts, for which we would be remunerated.

In renewable energy we expect to find opportunities to expand some of our assets or to repower them.

Increase cash available for distribution by investing in new sustainable infrastructure, including renewable energy, storage, efficient natural gas, transmission and transportation infrastructure, district heating as well as water assets

We will seek to grow our cash available for distribution to shareholders by investing in new assets, generally contracted or regulated. We expect to acquire assets from third parties leveraging the local presence and network we have in the geographies and sectors in which we operate. We have also entered into and intend to enter into agreements or partnerships with developers or asset owners to acquire assets. We also invest in assets under development or construction either directly or with partners via investment vehicles. We also have a ROFO agreement with AAGES. 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 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 mitigate the risk of our investments by pursuing proven technologies in which we generally have significant experience, located in countries where we believe conditions to be stable and safe. In certain situations, we could invest, or co-invest with partners, in assets under development, in assets with shorter or partially contracted revenue period, or subject to regulation, or in assets with revenue in currencies other than U.S. dollar or euro.

Additionally, our policies and management systems include thorough risk analysis and risk management processes that we apply whenever we acquire an asset, and which we are obligated to review periodically throughout the life of the asset. Our policy is to insure all of our assets whenever economically feasible, retaining in some cases part of the risk in house.

Maintain a prudent financial policy and financial flexibility

Project debt is an important principle for us. We intend to finance 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, 2020, approximately 93% of our total interest risk exposure was fixed or hedged, generally for the long-term. We also intend to 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 intend to maintain a solid financial position through a combination of cash on hand and undrawn credit facilities. In order to maintain financial flexibility, we use diversified sources of financing in our project and corporate debt including banks, capital markets and private investor financing. In recent years we have been active in green financing initiatives, improving our access to new debt investors.

Our Competitive Strengths

We believe that we are well-positioned to execute our business strategies thanks to the following competitive strengths:

Stable and predictable long-term cash flows

We believe that our portfolio of sustainable infrastructure has a stable cash flow profile. The off-take agreements or regulation in place at our assets have a weighted average remaining term of approximately 17 years as of December 31, 2020, providing long-term cash flow visibility. In 2020, approximately 55% of our revenue was related to availability payments in the different business sectors in which we operate, which includes our transmission lines, our efficient natural gas plant ACT, our water assets and approximately 70% of the revenue received from our Spanish solar assets. In these assets, our revenue does not depend (or has low dependence) on solar or wind resources, which translates in a more stable cash-flow generation. 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 would apply if we were a corporation based in the United States 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, we do not expect to pay significant income tax in the upcoming years in most of our geographies due to existing net operating losses, or NOLs. See “Item 3.D—Risk Factors—Risks Related to Taxation—Our future tax liability may be greater than expected if we do not use NOLs sufficient to offset our taxable income,” “Item 3.D—Risk Factors—Risks Related to Taxation—Our ability to use U.S. NOLs to offset future income may be limited” and “Item 3.D—Risk Factors—Risks Related to Taxation—Changes in our tax position can significantly affect our reported earnings and cash flows.” Furthermore, based on our existing portfolio of assets, we believe that there is limited repatriation risk in the jurisdictions in which we operate. See “Item 3.D—Risk Factors—Risks Related to Our Business and the Markets in Which We Operate—We have international operations and investments, including in emerging markets that could be subject to economic, social and political uncertainties.”

Positioned in business sectors with high growth prospects

The renewable energy industry has grown significantly in recent years and it is expected to continue to grow in the coming decades. According to Bloomberg New Energy Finance 2020, renewable energy is expected to account for the majority of new investments in the power sector in most markets. By 2050, approximately 68% of the world’s power generation is expected to come from renewable energy sources, demonstrating that renewable energy is becoming mainstream. Global installed capacity is expected to shift from 56% fossil fuels today to approximately two-thirds renewables by 2050. A 14-terawatt expansion of generating capacity is estimated to require approximately $15.1 trillion of new investment between now and 2050 – of which approximately 73% is expected to go to renewables. Another approximately $1 trillion of investment is expected in batteries along with an estimated $14 trillion in transmission and distribution during that same period. 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 wind and solar energy generation. We believe that we are well positioned in sectors with solid growth expectations.

We also believe that our exposure to international markets will allow us to pursue improved growth opportunities and achieve higher returns than we would have if we had a narrow geographic or technological focus. If certain geographies and business sectors become more competitive for asset acquisitions for some time, we believe we can continue to execute on our growth strategy investing in other regions or in other business sectors where we are present.

Well positioned in ESG

In 2020, 73.6% of our Adjusted EBITDA related to renewable energy and 69.4% of our Adjusted EBITDA corresponded to solar energy production. Adjusted EBITDA including unconsolidated affiliates from low carbon footprint represented 87.3%, including renewable energy, transportation and transmission infrastructure, district heating as well as water assets. We have set a target to maintain over 80% of our Adjusted EBITDA including unconsolidated affiliates generated from low-carbon footprint. We have also set a target to reduce our Greenhouse Gas Emissions per unit of energy generated by 10% by 2030.

In terms of the social dimension of ESG, health and safety is our number one priority and we have continued to improve our key metrics. 2020 was the sixth consecutive year we have improved our key health and safety indicators, achieving a Lost Time Injury Rate of 0.3 and a Total-Record Incident Rate of 1.0. During the last few months we proactively donated protective equipment and basic goods to some of the COVID-19 affected local communities where we operate.

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 2020, the Board approved a board diversity policy. 25% of our directors are women.

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

A sustainable growth strategy

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 have also entered into and intend to enter into agreements or partnerships with developers or asset owners to acquire assets that are either in operation, or under construction or development. We also invest in assets under development or construction either directly, or with partners via investment vehicles. We also have a ROFO agreement with AAGES.

Our Operations

Renewable energy

Solana

Overview. Solana is a 250 MW net (280 MW gross) solar plant located in Maricopa County, Arizona, approximately 70 miles southwest of Phoenix. Solana uses a conventional parabolic trough solar power system to generate electricity, including a 22-mile 230kV transmission line and a molten salt thermal energy storage system. Solana reached COD on October 9, 2013.

PPA. Solana has a 30-year, fixed-price PPA with Arizona Public Service Company, or APS, for at least 110% of the output of the project. The PPA provides for the sale of electricity at a fixed base price approved by the Arizona Corporation Commission with annual increases of 1.84% per year. The PPA includes on-going performance obligations. The PPA expires in 2043.

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

Operations. Solana has not yet achieved its technical capacity on a continuous basis. During the last few years, repairs and improvements were conducted on the steam generator, the water plant and the storage system. In 2020, availability in the storage system was lower than expected due to certain leaks in the storage system in the first quarter of 2020. Improvements and equipment replacements are required over time, which have impacted production in 2020 and will continue to impact production in 2021, with the exact scope and timing of repairs subject to review. Solana has a cash repair reserve account funded with approximately $54 million that we expect to use partially or totally for this purpose. We cannot assure that the improvements and equipment replacements made will be effective or sufficient.

Project Level Financing. Solana received a loan from the FFB in December 2010, with a guarantee from the DOE. The long-term tranche is payable over a 29-year term and has an average fixed interest rate of 3.67%. The principal balance was $777 million as of December 31, 2020. 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. In 2013, Abengoa entered into an agreement with Liberty, pursuant to which Liberty agreed to invest $300 million for all of the Class A membership interests of ASO Holdings Company LLC, the parent of Arizona Solar, as a tax equity investor. On August 17, 2020, we closed the acquisition of the Liberty Ownership Interest in Solana (See “—Acquisitions—2020 and 2021 acquisitions”). Since then we are the sole owner of the asset.

 Mojave

Overview. Mojave is a 250 MW net (280 MW gross) solar plant wholly-owned by us located in San Bernardino County, California, approximately 100 miles northeast of Los Angeles. Mojave relies on a conventional parabolic trough solar power system to generate electricity. Mojave reached COD in December 2014.

PPA. Mojave has a 25-year, fixed-price PPA with Pacific Gas & Electric Company, or PG&E, for 100% of the output of Mojave which began on COD. The PPA provides for the sale of electricity at a fixed base price with seasonal adjustments and adjustments for time of delivery. Mojave can deliver and receive payment for at least 110% of contracted capacity under the PPA. The PPA expires in 2039.

On January 29, 2019, PG&E filed for reorganization under Chapter 11 of the Bankruptcy Code in the U.S. Bankruptcy Court for the Northern District of California and on July 1, 2020 PG&E emerged from Chapter 11. See “Item 3.D—Risk Factors— Counterparties to our off-take agreements may not fulfill their obligations and, as our contracts expire, we may not be able to replace them with agreements on similar terms in light of increasing competition in the markets in which we operate.”

PG&E has senior unsecured credit ratings of BB- from S&P, WR from Moody’s and BB from Fitch.

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

Project Level Financing. Mojave received a loan from the FFB in September 2011, with a guarantee from the DOE. The long-term tranche is payable over a 25-year term. The FFB loan has an average fixed interest rate of 2.75%. The principal balance of this tranche was $694 million as of December 31, 2020. The financing arrangement permits dividend distributions on a semi-annual basis as long as the debt service coverage ratio is at least 1.20x. As a result of the PG&E Chapter 11, a technical event of default was triggered under our Mojave project finance agreement in July 2019 and the asset was not able to make distributions in 2019. The technical event of default was cured in 2020 after PG&E emerged from Chapter 11 and we made distributions from Mojave in 2020.

Chile PV 1 and Chile PV 2

In April 2020 we made an investment in the creation of a renewable energy platform in Chile, together with financial partners, where we now own approximately a 35% stake and have a strategic investor role. The platform intends to make further investments in renewable energy in Chile and sign PPAs with credit worthy off-takers.

Overview: Chile PV 1 and Chile PV 2 are two solar plants with 55 MW and 40 MW respectively. Both assets are owned through the renewable energy platform created in Chile in 2020. Chile PV 1 reached COD in 2016 and Chile PV 2 reached COD in 2017.

PPA: Chile PV 1 sells its production in the Chilean power market. Chile PV 2 has a PPA signed for part of its production.

O&M: Chile PV 1 and Chile PV 2 have O&M agreements with third parties.

Project Level Financing: The renewable energy platform has long-term project finance agreements in place in US$ for approximately $100 million. Payments are made semi-annually. The debt bears interest based on six-month LIBOR and more than 75% has been hedged. The financing arrangements permit dividend distributions at least once per year subject to meeting the debt service coverage ratios required by contract.

Spanish Solar Assets

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 consist of solar platforms generally of two 50 MW solar plants, with the exception of Solnova 1, 3 & 4, (which has three 50 MW solar plants) and PS10 & 20 (which is a 31 MW solar power complex). Except for PS10 & PS20, 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 United States.

O&M services are provided by Abengoa through all-in contracts, except for Seville PV, where O&M services are provided by Prodiel.

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

Solaben 2 & 3

Overview. Solaben 2 and Solaben 3 are two 50 MW solar plants located in Extremadura, Spain. Atlantica owns 70% of each asset and Itochu, a Japanese trading company, owns the remaining 30%. The assets reached COD in 2012.

O&M. Abengoa provides O&M services under an all-in contract that we could terminate every third year starting in December 2015.

Project Level Financing. In December 2010, Solaben 2 and Solaben 3 each entered into a euro denominated 20-year loan agreement with a syndicate of banks. The loan for Solaben 2 was for €169.3 million and the loan for Solaben 3 was for €171.5 million. The interest rate for each loan is a floating rate based on six-month EURIBOR plus a margin of 1.5%. We hedged our EURIBOR exposure:


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

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60% through a cap set at approximately 1% until 2025.

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From January 2026 40% through a cap with approximately 3.75% strike for the duration of the loans.

The outstanding amount of these loans as of December 31, 2020 was $138 million for Solaben 2 and $141 million for Solaben 3. The financing arrangements permit cash distribution to shareholders twice per year if the debt service coverage ratio is at least 1.10x.

In addition, on April 8, 2020, Logrosan Solar Inversiones, S.A, the subsidiary-holding company of Solaben 2 & 3 and Solaben 1 & 6 entered into the Green Project Finance with ING Bank, B.V. and Banco Santander S.A. The facility is a green project financing euro-denominated agreement that has a notional of €140 million of which 25% is progressively amortized over its 5-year term and the remaining 75% is expected to be refinanced at maturity. The Green Project Finance is guaranteed by the shares of Logrosan and its lenders have no recourse to Atlantica corporate level. Interest accrue at a rate per annum equal to the sum of 6-month EURIBOR plus a margin of 3.25% and we hedged the EURIBOR with a 0% cap for the total amount and the entire life of the loan. The outstanding amount of this facility as of December 31, 2020, was $165 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 1.60x 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 1.20x.

Solacor 1 & 2

Overview. Solacor 1 and Solacor 2 are two 50 MW solar plants located in Andalusia, Spain. Atlantica owns 87% and JGC Corporation, a Japanese engineering company, holds the remaining 13%. The assets reached COD in 2012.

O&M. Abengoa provides O&M services under an all-in contract that we could terminate every third year starting in December 2015.

Project Level Financing. In August 2010, Solacor 1 & 2 entered into 20-year loan agreements with a syndicate of banks for a total amount of €353 million. The interest rate for the loans is a floating rate based on six-month EURIBOR plus a margin of 1.5%. We hedge our EURIBOR exposure:

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

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

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In addition, we contracted caps with a 1% strike covering 19.3% of the principal of Solacor 1 and 18.2% of the principal of Solacor 2. Both caps hedge the interest rate through 2025.

The total outstanding amount of these loans as of December 31, 2020 was €275 million. These financing arrangements permit cash distribution to shareholders twice per year if the debt service coverage ratio is at least 1.10x.

PS10 & 20

Overview. PS10 & 20 is a 31 MW solar complex wholly owned by us located in Andalusia, Spain. PS10 reached COD in 2007 and PS20 reached COD in 2009.

O&M. Abengoa provides O&M services through a 21-year all-in contract.

Project Level Financing. In 2006, PS10 and PS20 entered into a 21.5-year loan agreement and 24.5-year loan agreement respectively, which were subsequently increased in 2007 to €43.4 million for PS10 and €94.6 million for PS20. The interest rate for each loan is a floating rate based on six-month EURIBOR plus a margin of 1.0% to 1.10% (depending on the level of the debt service coverage ratio). We hedged 100% of our EURIBOR exposure for the life of the financing:


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30% for both loans through a swap set at approximately 4.07%

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70% for both loans through a cap set at approximately 1% until 2025

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From January 2026 70% through a cap with a 4.25% strike for PS10 and 4.5% for PS20

The outstanding amount of these loans as of December 31, 2020 were $25 million for PS10 and $66 million for PS20. These financing arrangements permit cash distribution to shareholders once per year if the debt service coverage ratio is at least 1.10x.

Helios 1 & 2

Overview. Helios 1 and Helios 2 are two 50 MW solar plants wholly owned by us located in Castilla la Mancha, Spain. The assets reached COD in 2012.

O&M. Abengoa provides O&M services through a 25-year all-in contract.

Project Level Financing. On July 14, 2020, we refinanced Helios 1 & 2. We entered into a senior secured note facility with a group of institutional investors as purchasers of the notes issued thereunder for a total amount of €325.6 million ($397.7 million approximately). The notes were issued on July 23, 2020 and have a 17-year maturity. Interest accrue at a fixed rate per annum equal to 1.90%. Debt repayment is semiannual over the 17-year tenor of the debt. The outstanding amount of the debt as of December 31, 2020 was $369 million. The note facility permits cash distributions to shareholders if the debt service coverage ratio is at least 1.15x.

Helioenergy 1 & 2

Overview. Helioenergy 1 and Helioenergy 2 are two 50 MW solar plants wholly owned by us located in Andalusia, Spain. They reached COD in 2011.

O&M. Abengoa provides O&M services through a 20-year all-in contract.

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


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a 15-year loan agreement of €218.5 million with a syndicate of banks. The interest rate for the loans is a floating rate based on six-month EURIBOR plus a margin of 2.25% until December 2025 and 2.50% until maturity. The banking tranche is 97% hedged through a swap set at approximately 3.8% strike and 3% hedged through a cap with a 1% strike.

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

The outstanding amount of these loans as of December 31, 2020 was $308 million. The financing arrangements permit cash distributions to shareholders semi-annually based on a debt service coverage ratio of at least 1.15x.

Solnova 1, 3 & 4

Overview. Solnova 1, Solnova 3 and Solnova 4 are three 50 MW solar plants wholly owned by us located in Andalusia, Spain, in the same complex as PS-10 and PS-20. Solnova 1, 3 & 4 projects reached COD in 2010.

O&M. Abengoa provides O&M services through a 25-year all-in contract.

Project Level Financing. In December 2007, Solnova 1 entered into a 22-year loan agreement for €233.4 million with a syndicate of banks. The interest rate for the loan is a floating rate based on six-month EURIBOR plus a margin in the range of 1.15% up to 1.25%, depending on the debt service coverage ratio. The principal is hedged:


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78% through a swap set at approximately 4.76% strike for the life of the debt.

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22% through a cap with a 1% strike covering the principal through 2025.

In January 2008, Solnova 3 entered into a 22-year loan agreement for €227.5 million with a syndicate of banks. The interest rate for the loan is a floating rate based on six-month EURIBOR plus a margin in the range from 1.15% up to 1.25%, depending on the debt service coverage ratio. The principal is hedged:


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

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

In August 2008, Solnova 4 entered into a 22-year loan agreement for €217.1 million with a syndicate of banks. The interest rate for the loan is a floating rate based on six-month EURIBOR plus a margin in the range from 1.50% up to 1.60%, depending on the debt service coverage ratio. The principal is hedged:


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

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

As of December 31, 2020, the outstanding amount of these loans was $509 million. The financing arrangements of the three plants permit cash distributions to shareholders once per year if the debt service coverage ratio is at least 1.15x.

Solaben 1 & 6

Overview. Solaben 1 and Solaben 6 are two 50 MW solar plants wholly owned by us located in Extremadura, Spain, in the same complex as Solaben 2 & 3. Solaben 1 & 6 reached COD in the third quarter of 2013.

O&M. Abengoa provides O&M services through a 25-year all-in contract.

Project Level Financing. On September 30, 2015, Solaben Luxembourg S.A., a holding company of the two project companies, issued a project bond for €285 million. The bonds mature in December 2034. The bonds have a coupon of 3.758% and interest are payable in semi-annual instalments on June 30 and December 31 of each year. The principal of the bonds is amortized over the life of the bonds. The outstanding amount of the project bonds as of December 31, 2020 was $246 million. The financing arrangements of the plants permit cash distributions to shareholders once per year if the debt service coverage ratio is at least 1.650x.

Seville PV

Overview. Seville PV is a 1 MW photovoltaic farm located alongside PS 10 & 20 and Solnova 1, 3 & 4, in Andalusia, Spain. Seville PV reached COD in 2006.

O&M. Seville PV has an O&M agreement in place with Prodiel.

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

Kaxu

Overview. Kaxu is a 100 MW net solar plant located in Pofadder, Northern Cape Province, South Africa. The project company is currently owned by us through ABY Solar South Africa (Pty) Ltd (51%), Industrial Development Corporation of South Africa (29%) and Kaxu Community Trust (20%). Kaxu relies on a conventional parabolic trough solar power system to generate electricity. This technology is similar to the technology used in solar power plants that we own in the U.S. and Spain. It also has a molten salt thermal energy storage system. The asset reached COD in January 2015.

PPA. Kaxu has a 20-year PPA with Eskom, under a take–or-pay contract for the purchase of electricity up to the contracted capacity from the facility. The PPA expires in February 2035. Eskom purchases all the output of the Kaxu plant under a fixed-price formula in South African Rand subject to indexation to local inflation.

Eskom is a state-owned, limited liability company, wholly owned by the government of the Republic of South Africa. Eskom’s payment guarantees are underwritten by the South African Department of Energy, under the terms of an implementation agreement. Eskom’s credit ratings are currently CCC+ from S&P, Caa1 from Moody’s and B from Fitch. The Republic of South Africa’s credit ratings are currently BB from S&P, Ba2 from Moody’s and BB- from Fitch.

In addition, in 2019 we entered into a political risk insurance agreement with the Multinational Investment Guarantee Agency for Kaxu. The insurance provides protection for breach of contract up to $89.9 million in the event the South African Department of Energy does not comply with its obligations as guarantor. This insurance policy does not cover credit risk.

O&M. O&M services are provided by Abengoa under a 20-year contract.

Project Level Financing. Kaxu entered into a long-term financing agreement with a lenders’ group for a total initial amount of approximately ZAR 5,860.0 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 9.5% considering the hedge in place. As of December 31, 2020, the outstanding amount of these loans was ZAR 5,222 million, or approximately $355 million.

The financing arrangement permits dividend distributions on a semi-annual basis after the first repayment of debt has occurred, as long as the historical and projected debt service coverage ratios are at least 1.2x.

The project financing arrangement for Kaxu contains cross-default provisions related to Abengoa such that debt defaults by Abengoa, subject to certain threshold amounts and/or a restructuring process, could trigger a default under the Kaxu project financing arrangement. In December 2020, we obtained a waiver from Kaxu’s project debt lenders in which they commit not to take any action until December 31, 2021 with respect to any potential cross-defaults with Abengoa for the pre-insolvency filing of August 2020. The insolvency filing by the individual company Abengoa, S.A. in February 2021 represents a theoretical event of default under the Kaxu project finance agreement for which we do not yet have a waiver. Although we do not expect the Kaxu’s project debt lenders to accelerate the debt or take any other action, a cross-default scenario, if not cured or waived, may entitle lenders to demand repayment, limit distributions from the asset or enforce on their security interests, which may have a material adverse effect on our business, financial condition, results of operations and cash flows. See “Item 3.D — Risk Factors— Risks Related to Our Relationship with Algonquin and Abengoa— If Abengoa defaults on certain of its debt obligations, we could potentially be in default of certain of our project financing agreements.”

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, a global leader in the manufacture and maintenance of wind turbines, and each turbine has a nominal capacity of 2 MW. The plant reached COD in May 2014.

PPA. Palmatir signed a PPA with UTE in September 2011 for 100% of the electricity produced. UTE pays a fixed tariff under the PPA, which is denominated in U.S. dollars and will be partially adjusted annually based on a formula referring to U.S. CPI, Uruguay’s CPI and the applicable UYU/U.S. dollar exchange rate.

O&M. We perform O&M with our own personnel, and we have a turbine O&M agreement with Siemens that covers scheduled and unscheduled turbine maintenance, a supply of spare parts, wind farm monitoring and reporting services.

Project Level Financing. On April 11, 2013, Palmatir entered into a financing agreement for a 20-year loan in two tranches in connection with the project, denominated in USD. The first tranche is a $73 million loan with a fixed interest rate of 3.16%. The second tranche is a $40 million loan with a floating interest rate of six-month U.S. LIBOR plus 4.125%, which was 80% hedged with a swap at a rate of 2.22%. The combined principal balance of both tranches as of December 31, 2020 was $82 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. Cadonal reached COD in December 2014.

PPA. Cadonal signed a PPA with UTE on December 28, 2012, for 100% of the electricity produced. UTE pays a fixed tariff under the PPA, which is denominated in U.S. dollars and is partially adjusted annually based on a formula referring to U.S. CPI, Uruguay’s CPI and the applicable UYU/U.S. dollar exchange rate.

O&M. We perform O&M with our own personnel, and we have a turbine O&M agreement with Siemens that covers scheduled and unscheduled turbine maintenance, a supply of spare parts, wind farm monitoring and reporting services.

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


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Tranche A is a $36.0 million loan with maturity in 2034 and a floating interest rate of six-month LIBOR plus 2.9%, 81% hedged with a swap set at approximately 3.29% strike.

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Tranche B is a $33.5 million loan with maturity in 2032 and a floating interest rate of six-month LIBOR plus 2.65%, 81% hedged with a swap set at approximately 3.16% strike.

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

The combined principal balance of these loans was $63 million as of December 31, 2020. The financing arrangements of the plant permits cash distributions to shareholders twice a year subject to, among other things, a senior debt service coverage ratio for the previous twelve-month period of at least 1.20x and a total debt service coverage ratio for the previous twelve-month period being at least 1.10x.

Melowind

Overview. Melowind is an onshore 50 MW wind farm facility wholly owned by us, located in Cerro Largo, 200 miles north of the city of Montevideo, Uruguay. Melowind has 20 wind turbines supplied by Nordex, each with a capacity of 2.5 MW. The asset reached COD in November 2015.

PPA. Melowind signed a PPA with UTE in 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. dollar exchange rate.

O&M. We perform O&M with our own personnel, and we have a turbine O&M agreement with Nordex that covers scheduled and unscheduled turbine maintenance.

Project Level Financing. On December 13, 2018, Melowind entered into a financing agreement payable over a period of 16 years. The financing consists of a $76 million loan with a floating interest rate based on six-month LIBOR plus a margin of 2.25% until December 2021, 2.5% from January 2022 to December 2024, 2.75% from January 2025 to December 2027 and 3.0% from January 2028 to December 2034. LIBOR exposure was 75% hedged with a swap at a rate of 3.26% with the financing bank. As of December 31, 2020, the outstanding amount of the loan was $73 million.

The financing arrangement permits cash distributions to shareholders semi-annually subject, among other things, to a historical debt service coverage ratio for the previous twelve-month period of at least 1.15x.

Mini-hydro Peru

Overview. Mini-hydro Peru is a 4 MW mini-hydroelectric power plant located approximately 99 miles from Lima. The plant reached COD in April 2012.

Concession Agreement. It has a 20-year fixed-price concession agreement denominated in U.S. dollars with the Ministry of Energy of Peru and the price is adjusted annually in accordance with the U.S. Consumer Price Index.

O&M. The operation and maintenance service is performed internally.

Project Level Financing. The asset has a 17-year, non-recourse project financing with Inter-American Investment Corporation. As of December 31, 2020, the outstanding amount on the loan was $5 million.

Efficient Natural Gas

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, 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. Pemex has the possibility to terminate the CSA under certain circumstances paying an indemnity.

Conversion Services Agreement. On September 18, 2009, ACT entered into the Pemex CSA, with Pemex, under which ACT is required to sell all of the plant’s thermal and electrical output to Pemex. The Pemex CSA has an initial term of 19 years from the in-service date and will expire on March 31, 2033. The Pemex CSA requires Pemex to supply the facility, free of charge, with the fuel and water necessary to operate ACT, and the latter has to produce electrical energy and steam requested by Pemex based on the expected levels of efficiency. The Pemex CSA is denominated in U.S. dollars. The price is fixed and will be adjusted annually, adjustments will be made 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.

In recent years, Pemex’s credit rating has weakened and is currently BBB from S&P, Ba2 from Moody’s and BB- from Fitch. We have been experiencing significant delays in collections from Pemex since the second half of 2019.

O&M. GE provides services for the maintenance, service and repair of the gas turbines NAES is responsible for the O&M. The O&M agreement with NAES expires upon the expiration of the Pemex CSA, although we may cancel it with no penalty at any time.

We own all of the shares of ACT except for two ordinary shares, which represent less than 0.01% of the total capital of ACT and which are owned by wholly owned subsidiaries of Abengoa.

Project Level Financing. In January 2014, ACT Energy Mexico entered into a $675 million senior loan agreement with a syndicate of banks. The financing consists of a $205.4 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 U.S. LIBOR plus a margin of 3.5% from January 2019 to December 2024 and 3.75% from January 2025 to December 2031. The loan is 75% hedged at a weighted average rate of 3.94%.

The outstanding amount of these loans as of December 31, 2020 was $504 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 2018. The power plant is configured with seven Wärtsilä natural gas internal combustion engines.

We entered into a ROFO agreement with Arroyo Energy for the remaining 70% stake in Monterrey, currently owned by them.

PPA. It is a U.S. dollar-denominated 20-year PPA with two international large corporations engaged in the car manufacturing industry. The PPA also includes price escalation factors. The asset also has a 20-year contract for the natural gas transportation from Texas with a U.S. energy company. It has no commodity risk. Additionally, the asset expects to be able to sell electricity to the Mexican market if and when it is connected to the grid.

O&M. Wärtsilä performs the O&M for Monterrey. The term of the contract is three years from COD. In addition, the asset has in place a Generator Maintenance Agreement with Wärtsilä for the seven generators for a period of 15 years from COD.

Project Level Financing. Monterrey has a loan of approximately $169 million which matures in September 2027 and a credit line of $14 million available until September 2022, subject to certain conditions. The interest rate of the loan is a floating rate based on the three-month U.S. LIBOR plus a margin of 2.75% with a 0.25% increase after three years. The LIBOR exposure was 75% hedged with a swap rate of 2.34% 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.

Electric Transmission

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 to connect our line to the Shahuindo (ATN expansion 1) mine located nearby. In October 2019, we also closed the acquisition of ATN Expansion 2.

Concession Agreement. Pursuant to the initial concession agreement, the Peruvian Ministry of Energy, on behalf of the Peruvian Government, granted ATN a concession to construct, develop, own, operate and maintain ATN. ATN owns all assets that it has acquired to construct and operate ATN for the duration of the concession. The ownership of these assets will revert to the Peruvian Ministry of Energy upon termination of the initial concession agreement.

ATN has a 30-year fixed-price tariff base denominated in U.S. dollars that is adjusted annually in accordance with the U.S. Finished Goods Less Food and Energy Index as published by the U.S. Department of Labor. Our receipt of the tariff base is independent from the effective utilization of the transmission lines and substations. In addition, both ATN Expansion 1 and ATN Expansion 2 have 20-year PPAs denominated in US $.

O&M. ATN has a 27-year term O&M agreement with a subsidiary of Abengoa.

Project Level Financing. On September 26, 2013, ATN completed the issue of a project bond in four tranches denominated in USD:


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1st tranche, currently repaid, had a principal amount of $15 million with interest of 3.84% per year.

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2nd tranche has 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.

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3rd tranche has a principal amount of $45 million with a 26-year term and bears interest at a rate of 7.53% per year. The third tranche has a 15-year grace period for principal repayments.

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4th tranche has 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, 2020, $98 million in aggregate principal amount was outstanding. The project bond agreement permits cash distributions subject to a debt service coverage ratio for the last six months of at least 1.10x.

ATS

Overview. ATS is a 569 miles transmission line located in Peru wholly owned by us. ATS is part of the Guaranteed Transmission System and comprises several sections of transmission lines and substations. ATS reached COD in 2014.

Concession Agreement. The initial concession agreement became effective on July 22, 2010 and will expire 30 years after achieving COD. Pursuant to the initial concession agreement, ATS will own all assets it has acquired to construct and operate the ATS Project for the duration of the concession. These assets will revert to the Peruvian Ministry of Energy upon termination of the initial concession agreement.

The concession agreement has a fixed-price tariff base denominated in U.S. dollars and is adjusted annually in accordance with the U.S. Finished Goods Less Food and Energy Index as published by the U.S. Department of Labor. Our receipt of the tariff base is independent from the effective utilization of the transmission lines and substations related to the ATS Project.

O&M. ATS has a five-year term O&M agreement with a subsidiary of Abengoa.

Project Level Financing. On April 8, 2014, ATS issued a project bond denominated in U.S. dollars with a 29-year term with semi-annual amortization and which bears a fixed interest rate of 6.875%. As of December 31, 2020, $402 million was outstanding. The project bond agreement permits cash distributions every six months subject to a trailing historical debt service coverage ratio for the previous two quarters of at least 1.20x.

ATN2

Overview. ATN2, is an 81 miles transmission line located in Peru wholly owned by us, which is part of the Complementary Transmission System. ATN2 reached COD in June 2015.

ATN2 has an 18-year, fixed-price tariff base contract denominated in U.S. dollars with Minera Las Bambas. The tariff is partially adjusted annually in accordance with the U.S. Finished Goods Less Food and Energy Index as published by the U.S. Department of Labor. Our receipt of the tariff base is independent from the effective utilization of the transmission lines and substations related to ATN2.

Minera Las Bambas is owned by a partnership consisting of a China Minmetals Corporation subsidiary (62.5%), a wholly owned subsidiary of Guoxin International Investment Co. Ltd (22.5%) and CITIC Metal Co. Ltd (15.0%).

Maintenance & Monitoring. ATN 2 has a 6 year-term O&M agreement with a subsidiary of Abengoa,

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 5.8% on a weighted average basis and matures in 2031. As of December 31, 2020, the outstanding amount of the ATN2 project loan was $54 million. The loan agreement permits cash distributions subject to a debt service coverage ratio of at least 1.15x.

Quadra 1 & Quadra 2

Overview. Quadra 1 is a 49-mile transmission in Chile. Quadra 1 connects to the Sierra Gorda substation owned by Sierra Gorda SCM, a mining company and is located in the commune of Sierra Gorda. Quadra 2 is a 32-mile transmission asset that provides electricity to the seawater pump stations owned by the Sierra Gorda SCM in Chile. Quadra 1 and Quadra 2 reached COD in 2014.

Concession Agreement. Both projects have concession agreements with the Sierra Gorda SCM mining company, which is owned by Sumitomo Corporation, Sumitomo Metal Mining and KGHM Polska Mietz. The concession agreement is denominated in U.S. dollars and has a 21-year term that began on the COD. The contract price is indexed mainly to the U.S. CPI.

The concession agreement grants in favor of Sierra Gorda a call option over the transmission lines, exercisable at any time during the life of the contract. According to the call option, Sierra Gorda is entitled to purchase the transmission line at an agreed price and with a six-month prior written notice.

O&M. Enor performs operations services at Quadra 1 under a 10-year contract expiring in 2027. Gas Atacama provides operations services at Quadra 2 under a 12-year contract expiring in 2029. Cobra performs maintenance services at Quadra 1 and Quadra 2 under 6-year contracts expiring in 2023.

Project Level Financing. In June 2019, we refinanced the project debt of our Chilean assets Palmucho, Chile TL3, Quadra 1 and Quadra 2. This financing agreement consists of a single loan agreement for all these assets for a total amount of $75 million with a syndicate of local banks. The loan is denominated in U.S. dollars and matures on September 30, 2031. It has a semi-annual amortization schedule and accrues interest at a variable rate based on the six-month U.S. 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, 2020, the outstanding amount was $71 million. The financing agreement is cross collateralized jointly between the Chilean assets and permits cash distributions twice per year if the combined debt service coverage ratio for the three assets is at least 1.20x.

Palmucho

Palmucho is a transmission line in Chile of approximately 6 miles. Palmucho has a 14-year concession contract with Enel Generacion Chile, whereby both parties are obliged to enter into a four-year valid toll contract at the end of the term of the concession contract and the valid toll contract will be renewed for three periods of four years each until one of the parties decides not to renew. O&M services are provided by Cobra.

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

Chile TL3

Overview. Chile TL3 is a 50-mile transmission line in operation in Chile which reached COD in 1993. It generates revenue under the current regulation in Chile. The asset has a fixed-price tariff based on the return to the investment and the operating and maintenance costs denominated in U.S. dollars, and is partially adjusted annually in accordance with the U.S. and Chilean Consumer Price Indexes and currency exchange rates.

O&M. Operation services are performed internally. Cobra performs maintenance services at Chile TL3 under a 4-year contract expiring in 2022.

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

Water

Honaine

Overview. Honaine is a water desalination plant of 7 M ft3 per day capacity located in Taffsout, Algeria. We indirectly own 25.5% through Myah Bahr Honaine Spa (“MBH”), Algerian Energy Company, or AEC, owns 49% and Sacyr owns the remaining 25.5% of Honaine. Honaine reached COD in July 2012. AEC is the Algerian agency in charge of delivering Algeria’s large-scale desalination program.

The technology used in the Honaine plant is currently the most commonly used in this kind of asset. It consists of desalination using membranes by reverse osmosis.

Honaine has a corporate income tax exemption until 2021. 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 30-year take-or-pay contract with Sonatrach/Algerienne des Eaux, or ADE, from the date of execution, or 25-year term from COD. The tariff structure is based upon plant capacity and water production, covering variable cost (water cost plus electricity cost). Tariffs are adjusted monthly based on the indexation mechanisms that include local inflation, U.S. inflation and the exchange rate between the U.S. dollar and local currency.

Operations & Maintenance. Honaine has a 30-year contract with a joint venture between Abengoa (50%) and Sacyr (50%) from the date of the execution (or 25-year term from COD).

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. The financing arrangement permits cash distribution to shareholders once per year under certain conditions, including that the audited financials for the prior fiscal year indicate a debt service coverage ratio of at least 1.25x.

Skikda

Overview. The Skikda project is a 3.5 M ft3 per day capacity water desalination plant located in Skikda, Algeria. Skikda is located 510 km east of Algiers. We indirectly own 34.2% of Skikda through Aguas de Skikda, or ADS, AEC owns 49% and Sacyr owns the remaining 16.8%. 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 project has been compensated under the water purchase agreement in the tariff.

Concession Agreement. The water purchase agreement is a 30-year take-or-pay contract with Sonatrach/ADE from the date of execution, or 25-year term from COD. The tariff structure is based upon plant capacity and water production, covering variable cost (water cost plus electricity cost). Tariffs are adjusted monthly based on the indexation mechanisms that include local inflation, U.S. inflation and the exchange rate between the U.S. dollar and local currency.

O&M. Skikda has a 25-year contract from COD with a joint venture between Abengoa (67%) and Sacyr (33%).

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, 2020, the outstanding amount of the Skikda project loan was $17 million. The financing arrangement permits cash distribution to shareholders once per year under certain conditions, including that the audited financials for the prior fiscal year indicate a debt service coverage ratio of at least 1.25x.

Tenes

Overview. Tenes is a 7 M ft3 per day capacity water desalination plant located 208 km west of Algiers, in Algeria. Tenes uses the same technology as Honaine and Skikda, and has been in operation since 2015. Befesa Agua Tenes has a 51.0% stake in Ténès Lilmiyah SpA and we have a majority at the Board of Directors of Befesa Agua Tenes, the remaining 49% is owned by AEC.

Since January 2019, we have an investment in Tenes through a secured loan to be reimbursed by Befesa Agua Tenes, together with 12% per annum interest, through a full cash-sweep of all the dividends to be received from the asset. On May 31, 2020, we entered into a new agreement which provides us with certain additional decision rights, and a majority at the Board of Directors of Befesa Agua Tenes. Therefore, we have concluded that we have control over Tenes since May 31, 2020 and as a result we have fully consolidated the asset from that date.

Tenes had a corporate income tax exemption until 2025. After that period, in case the exemption is not extended, a claim may be made under the water purchase agreement for compensation in the tariff.

Concession Agreement. The water purchase agreement is a 25-year take-or-pay contract with Sonatrach/ADE from the date of execution, or 25-year term from COD. The tariff structure is based upon plant capacity and water production, covering variable cost (water cost plus electricity cost). Tariffs are adjusted monthly based on the exchange rate between the U.S. dollar and local currency and yearly based on indexation mechanisms that include local inflation and U.S. inflation.

O&M. Tenes has a 25-year contract from COD with Abengoa.

Project Level Financing. Tenes signed a financing agreement for $211 million. The loan accrues a fixed interest rate of 3.75%. The repayment of the facility agreement consists of sixty quarterly payments, ending in August 2031. As of December 31, 2020, the outstanding amount of the Tenes project loan was $98 million. The financing arrangements permit cash distribution to shareholders subject to a debt service coverage ratio of at least 1.10x.

Customers

We derive our revenue from selling electricity, electric transmission capacity and water desalination capacity. 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). We have one asset, Chile PV1, representing a very small percentage of our revenue, which sells electricity at market prices. See the description of each asset under “—Our Operations” for more detail on each concession contract.

Our main contracts in our business also include the project finance contracts with banks or financial institutions and the operation and maintenance contracts of each of our assets. See description of financing and operation and maintenance contracts under “—Our Operations.”

Competition

Renewable energy, storage, efficient natural gas and electric transmission are all capital-intensive and commodity-driven businesses with numerous industry participants. We compete based on the location of our assets in various countries and regions; however, because our assets typically have long-term contracts, competition with other asset operations is limited with respect to existing assets until the expiration of the PPAs. Power generation and transmission are highly regulated businesses in each country in which we operate and are currently highly fragmented and have a diverse industry structure. Our competitors have a wide variety of capabilities and resources. Our competitors include, among others, regulated utilities and transmission companies, other independent power producers and power marketers or trading companies and state-owned monopolies.

We also compete to acquire new projects with developers, independent power producers and financial investors, including pension funds and infrastructure funds and other dividend growth-oriented companies. Competitive conditions may vary over time depending on capital market conditions and regulation, which may affect the costs of constructing and operating projects.

Seasonality

Our operating results and cash flows can be significantly affected by weather in some of our most relevant projects, such as the solar power plants. We expect to derive a majority of our annual revenue in the months of May through September, when solar generation is the highest in the majority of our markets and when some of our off-take arrangements provide for higher payments to us. See “Item 3.D — Risk Factors—Risks Related to Our Business and Our Assets— The generation of electric energy from renewable energy sources depends heavily on suitable meteorological conditions, and if solar or wind conditions are unfavorable, our electricity generation, and therefore revenue from our renewable energy generation facilities using our systems, may be substantially below our expectations.

Environment and Sustainability

Environmental management is a key priority in our business and operations. Our facilities and operations are subject to significant government regulation, including stringent and comprehensive federal, provincial and local laws, statutes, regulations, guidelines, policies, directives and other requirements governing or relating to, among other things: air emissions; discharges into water; storage, handling, use, disposal, transportation and distribution of dangerous materials and hazardous, residual and other regulated materials, such as chemicals; the prevention of releases of hazardous materials into the environment; the presence and remediation of hazardous materials in soil and groundwater, both on and offsite; the protection of natural resources; land use and zoning matters; and workers’ health and safety matters. We consider environmental protection as an area of performance and as such, environmental issues are included among the responsibilities of our key executives.

Employees and Human Resources

As December 31, 2020, we had 456 employees (including both operation and maintenance and general and administrative staff). Following our acquisition of ASI Operations, the subsidiary which provides operation and maintenance services in the U.S., certain of our employees now belong to a labor union. We believe that the relationship between the Company and its labor union is good. We have not experienced any strikes or work stoppages amongst our workforce. One of our plants has experienced strikes by employees working for one of our operation and maintenance suppliers in the past.

Health & Safety

Within our values, the first one is “Integrity, Compliance and Safety”. We are committed to prioritizing and actively promoting health and safety as a tool to protect the integrity and health of our employees, subcontractors and partners involved in our business activity. We promote a safe operating culture across Atlantica and encourage a preventive culture in the operation and maintenance (“O&M”) activities of our subcontractors as reflected in our corporate health and safety policy.

Annually, we conduct internal and external audits to evaluate our health and safety management system in accordance with the OHSAS:18001 standard requirements. The external audit is carried out by an independent third party. These efforts have resulted in the continuation of the certification of the Occupational Health and Safety Management System in OHSAS: 18001 obtained in 2015. This certification has been successfully renewed during the last four years. Additionally, we perform periodic health and safety audits to our asset contractors to monitor the 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 safety key metrics targets in all our assets which include both Atlantica and subcontractor employees.
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 worked hours. We ended 2020 at 1.0, representing a 17% improvement versus 2019.

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 worked hours. LTIR for the year 2020 remained stable at 0.3 versus 2019.

Operation and Maintenance

In terms of operational efficiency, we focus on ensuring long-term availability, reliability and asset integrity with maintenance and monitoring. We, or the original owner of the asset, selected the suppliers of our solar panels, turbines, transmission towers and equipment 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 the assets. Additionally, we require all our suppliers to comply with our Suppliers’ Code of Conduct.

Operation and maintenance services for certain of our assets are provided by subsidiaries of Abengoa, S.A. On February 22, 2021, Abengoa, S.A. filed for insolvency proceedings in Spain. Based on the public information filed in connection with these proceedings, such insolvency proceedings do not include other Abengoa companies, including Abenewco1, S.A., the controlling company of the subsidiaries performing the operation and maintenance services for us. Although we have contingency plans in place, including a potential change of supplier and/or internalization, in the short term we expect the operation and maintenance services to continue to be provided by our current supplier. See “Item 3.D—Risk Factors—If Abengoa defaults on certain of its debt obligations, we could potentially be in default of certain of our project financing agreements”
 

Legal Proceedings

A number of Abengoa’s subcontractors and insurance companies that issued bonds covering Abengoa’s obligations under such contracts in the U.S included some of the non-recourse subsidiaries of Atlantica in the U.S. at the time of the construction of the plants we currently own as co-defendants in claims against Abengoa. Generally, the subsidiaries of Atlantica were dismissed as defendants at early stages of the processes. With respect to a claim addressed by a group of insurance companies to a number of Abengoa’s subsidiaries and to Solana (Arizona Solar One) for Abengoa related losses of approximately $20 million that could increase, according to the insurance companies, up to a maximum of approximately $200 million if all their exposure resulted in losses. Atlantica reached an agreement with all but one of the above-mentioned insurance companies, under which they agreed to dismiss their claims in exchange for payments of approximately $4.3 million, which were paid in 2018. The insurance company that did not join the agreement has temporarily stopped legal actions against Atlantica, and Atlantica does not expect this particular claim to have a material adverse effect on its business.

In addition, 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 executed $2.5 million from the escrow account and Abengoa reimbursed such amount according to the indemnities in force between Atlantica and Abengoa. The payments by Atlantica would only happen if and when the actual loss has been confirmed and after arbitration if the Company initiates it. We 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.

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 the aggregate, 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 operated 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 Federal Energy Regulatory Commission (“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 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 2005 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 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 2005. The senior debt for Solana and Mojave is guaranteed by the DOE pursuant to the Section 1705 loan guarantee program.

State and Local Regulation of the Electricity Industry in the United States

State regulatory agencies in the United States have jurisdiction over the rates and terms of electricity service to retail customers. Regulated investor-owned utilities often must obtain state approval for the contracts through which they purchase electricity, including renewable energy, if they seek to pass along the costs of these contracts to their retail ratepayers. Different states apply different standards for determining acceptable prices for utility procurement contracts, including PPAs. Our electricity generation project companies operate in Arizona and California. Information about the regulatory frameworks in Arizona and California is provided below.

United States State-Level Incentives

In addition to federal legislation, many states have enacted legislation, principally in the form of renewable portfolio standards, or RPS, which generally require electric utilities to generate or purchase a certain percentage of their electricity supplied to consumers from renewable resources. In certain states, it is not only mandatory to meet these percentages, which in general are on the increase from renewable resources, but also electric utilities may be required to generate or purchase a percentage of their electricity supplied to consumers from specific renewable energy technologies, including solar technology.

Arizona

The Arizona Corporation Commission (“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 (“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 is 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 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 CPUC, governs, among other entities, California’s investor-owned utilities, including Pacific Gas & Electric Company, or PG&E. The CPUC reviewed Mojave’s PPA and approved the contract by issuing a formal decision in November 2011.

Mojave must maintain compliance with the 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 entirety and
 

Imports for Independent Consumption. The import of power is used for self-supply purposes.
 
Since the energy reform of December 2013 and the enactment of the Electric Industry Law (Ley de la Industria Eléctrica), the power generation sector has been more open to private participation and investment, creating a competitive spot market in power generation, although electric transmission and distribution remain public services to be provided exclusively by CFE. The national electric grid is a responsibility of the Centro Nacional de Control de Energía, or the CENACE, which became a decentralized public agency, an Independent System Operator, or ISO.

Since the energy reform process started, secondary legislation and regulation was enacted derived from such amendments to the Mexican Constitution as published in the Official Federal Gazette, or Diario Oficial de la Federacion, on August 11, 2014. The changes made by the energy reform were implemented through a profound modification of the legal framework that had governed the development of the energy industry in the country.

However, on February 1st, 2021, Mexico´s President proposed a preferential reform to the Electricity Industry Act, meaning that the Congress shall vote on it no later than April 30th. In broad terms, the reform aims for CFE to recover the preponderance that it lost 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 force the termination of self-supply legacy 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 of deciding which generation permits are granted by the Federal Energy Regulatory Commission.

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 contaminating 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 MEM 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) provider-traders, (iii) non-provider traders, or (iv) qualified users, prior to execution of the corresponding agreement with CENACE. Transactions carried out within the MEM must be formalized through “electric coverage agreements” executed by and between such MEM participants. Generators, as MEM participants may, sell their generated energy and both traders and qualified users may purchase such energy through CENACE, which is the independent operator of the electric system.

CENACE is responsible for managing the supply and demand of MEM participants, conducting transactions and continuously generating prices. The price to be paid in MEM transactions has to be a “competition price” in terms of the Electric Industry Law and has to reflect elements such as electricity generation costs and other operating costs, as well as the amount of electricity demanded by and supplied within the MEM. Such competition price serves as a reference for long-term supply agreements between providers and qualified users, partially replacing the CFE-published tariffs.

Even though the Electric Industry Law provides the general guidelines to which the operation of the MEM is subject, on September 8, 2015, the Mexican Ministry of Energy published the Guidelines of the Market (Bases del Mercado Eléctrico), as the general administrative provisions which establish the principles for the design and operation of the MEM. The regulations list certain topics which are described in depth in the Rules of the Market (Reglas del Mercado), such as the methodology that is used to forecast the level of demand in the spot market, information on market participants, and the methodology to determine the price of the electricity sold and purchased within the spot market.

The Guidelines are part of the Rules of the Market, which are administrative provisions of general application that specifically detail different aspects of the operation of the MEM, and determine the rules that all market participants, such as generators, traders, suppliers, non-supplier traders or qualified users, as well as the competent authorities must comply with.

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).
 

Network’s Code (Código de Red).
 

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 Electricity 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 NationalElectric 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).
 
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, or Sistema Garantizado de Transmisión (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, or Sistema Complementario de Transmisión (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. Under SGT Concession Agreements, the concessionaire shall build the lines and be responsible for their operation and maintenance. Recovery of the investment during the term of the contract (up to 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.

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 Article 26 of Law 28832 and Article 27 of the Transmission Rules, or Reglamento de Transmision, approved by the Supreme Decree No. 027-2007-EM.

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, approved by Supreme Decree No. 020-97-EM, and the National Power Code, may result in the imposition of penalties, fines and restrictions. In addition to these penalties, fines and restrictions, if our concession is terminated due to the breach of obligations under the Concession Agreements, the Peruvian Ministry of Energy may appoint an intervenor to supervise the operations related to the concession to ensure the continuity in the provision of the service, and the compliance with applicable laws and regulations.

If a concessionaire suspends or interrupts the service for reasons other than regular maintenance and repairs, force majeure events, or failures caused by third parties, such concessionaire may be required to indemnify those who were affected for the damages caused by any such service interruption, in accordance with applicable regulations.

Electricity Legal Framework

The principal laws and regulations governing the Peruvian power sector, or the Power Legal Framework, are: (i) the Power Concessions Law (or Ley de Concesiones Electricas, PCL), approved by Law No. 25844, and its implementing rules (Supreme Decree No. 09-93-EM); (ii) the Law to Ensure the Efficient Development of Electricity Generation (or Ley para Asegurar el Desarrollo Eficiente de la Generacion Electrica), approved by Law No. 28832, or Law No. 28832; (iii) the Transmission Rules (or Reglamento de Transmision), approved by the Supreme Decree No. 027-2007-EM, or the Transmission Rules; (iv) the General Environmental Law (Law No. 28611); (v) the new Regulations for the Environmental Protection in Power Activities, approved by Supreme Decree No. 014-2019-EM, published on July 7, 2019; (vi) the Power Sector Antitrust Law (Law No. 26876) and its regulations (Supreme Decree No. 017-98-ITINCI); (vii) the Laws creating OSINERGMIN (Law No. 26734 and Law No. 28964); (viii) the OSINERGMIN Rules (Supreme Decree No. 054-2001-PCM); (ix) the Regulatory Agencies of Private Investment in Public Services Framework Law (Law No. 27332); and (x) the Legislative Decree that promotes investment in the generation of power through renewable resources (Legislative Decree No. 1002) and its regulations (Supreme Decree No. 012-2011-EM).

These laws 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.

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 the electrical activities (i.e. generation, transmission or distribution) the holder must obtain from the Ministry of Energy and Mines (hereinafter, “MINEM”) the Instrument for Environmental Management (hereinafter, “IEM”), which after its approval is mandatory for implementation.

By Supreme Decree No. 014-2019-EM, published on July 7, 2019, the MINEM approved the new Regulation for Environmental Protection in Electrical Activities (hereinafter, the “REPEA”).

The Guaranteed Transmission System—SGT Concession Agreement

ATN and ATS, as concessionaires, have SGT Concession Agreements granted by the Peruvian government as a result of a public tender. Under the SGT Concession Agreement, the Peruvian Ministry of Energy grants the concession necessary to construct, develop, own, operate, and maintain the transmission lines and substations comprising a project to provide electricity transmission services that has been included in the Peruvian transmission plan.

The SGT Concession Agreement must specify the works schedule of the project and the corresponding guaranties of compliance. It also specifies the causes of termination of the agreement. The SGT concessionaires are not obliged to pay the grantor any consideration for the SGT Concession Agreement.

Under the SGT Concession Agreement, the concessionaire shall build the lines and be responsible for their operation and maintenance. The recovery of the investment during the term of the contract (30 years) is guaranteed thereunder. The concessionaire owns the transmission assets during the term of the contract. Upon expiry of the contract the assets return to the state, which shall call a new tender if the lines are required at such time for the operation of the system.

The revenues of the project are established under the terms of the SGT Concession Agreement. In addition, the revenues of the project are funded by the users of electricity system. 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 Spain

Primary Rights and Obligations under the 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: In the case of existing facilities for the production of energy from renewable energy sources for which the specific remuneration system is recognized it is stablished a remuneration system based on the necessary participation in the market of these facilities, complemented by market income with a specific regulated remuneration that allows these technologies to compete on an equal conditions with the rest of the technologies on the market. This specific complementary remuneration will be sufficient to reach the minimum level necessary to cover the costs and enables them to compete on a level playing field with the other, non-renewable technologies on the market while achieving a reasonable return on investment. In case of new facilities, the Government can establish a specific remuneration and the granting of it would be via auction.
 
The significant obligations of the renewable energy electricity producers under the Electricity Act include, inter alia, a requirement to:
 

Offer to sell the energy they produce through the market operator even when they have not entered into a bilateral or forward contract and are consequently excluded from the bidding system managed by the market operator.

Maintain the plant’s planned production capacity. Power lines, which include connections with the transmission or distribution network and transformers are considered part of the production facility.
 
Additionally, the Royal Decree 413/2004 establishes the following relevant obligations for the 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.

Send of 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 electricity to obtain the following administrative authorizations:
 

Prior Administrative authorization (Autorización Administrativa Previa), which refers to the preliminary project of the installation as a technical document that will be processed, where appropriate, together with the environmental impact study.

Approval of the execution project (Autorización Administrativa de Construcción), which refers to the specific project of the facility and allows its owner to construct or establish it.

Operating permit (Autorización Administrativa de Explotación), which, once the project has been executed, allows the facilities to be energized and to proceed with their commercial exploitation.
 
Registration on Public Registers

The Electricity Act and Royal Decree 413/2014 require electricity generation facilities to be entered on the official register of electricity production plants maintained by the Ministry for Ecological Transition and the Demographic Challenge.

The autonomous regions may keep their own registers of electricity generation plants they have authorized if such plants have a capacity of 50 MW or less. The registration details of these plants must be provided to the Ministry for Ecological Transition and the Demographic Challenge.

To receive their facility-specific reimbursement, renewable energy facilities are required under the Electricity Act and Royal Decree 413/2014 to be recorded on a new register , known as the registry of the specific remuneration regime (“Registro de régimen retributivo específico” or “RRRE”). Unregistered plants will only receive the pool price.

The first transitional provision of Royal Decree 413/2014 states that power plants based on renewable sources recognized under the previous economic regime, as in the case of Solaben 2 & 3, Solacor 1 & 2, PS10 & 20 were automatically included in the RRRE.

Remuneration System for Renewable Plants

According to Royal Decree 413/2014, producers receive (i) the pool price for the power they produce and (ii) a specific remuneration.

A specific remuneration system applies to production facilities using renewable energy sources, high-efficiency cogeneration and waste that do not reach the minimum level necessary to cover the costs. It allows them to compete on an equal footing with the rest of the technologies on the market, obtaining a reasonable return. In order to determine the specific remuneration system applicable in each case, each installation, depending on its characteristics, will be assigned a standard installation which will be established according to technology, installed power, age, electrical system, etc. The specific remuneration of each installation will be obtained from the remuneration parameters of the corresponding standard installation and from the characteristics of the installation itself. For the calculation of the remuneration parameters of the standard installation, the values resulting from the competitive competition procedure shall be applied.

This specific remuneration system shall consist of:


a)
A remuneration per unit of installed power, which shall be called investment remuneration (Rinv) and shall be expressed in €/MW. To determine this parameter, the standard value of the initial investment resulting from the competitive tendering procedure established to grant the specific remuneration system to each installation will be considered. For the calculation of the annual income from the remuneration for the investment of an installation, the remuneration for the investment (Rinv) of the associated typical installation shall be multiplied by the power entitled to the specific remuneration system, without prejudice to the correction according to the number of equivalent hours of operation.


b)
A remuneration for the operation (Ro) which shall be calculated in accordance with the provisions of Article 17 of the Royal Decree 413/2014, expressed in €/MWh. In order to calculate the income from the remuneration for the operation of an installation, the remuneration for the operation (Ro) of the associated typical installation shall be multiplied, for each settlement period, by the energy sold on the production market in any of its forms of contracting in said period, attributable to the fraction of power entitled to a specific remuneration system, without prejudice to the correction based on the number of equivalent hours of operation.

For solar thermal plants, electrical energy attributable to the use of other fuels shall be excluded. The production of energy from the support fuel of solar thermal plants may not exceed 12 per cent of the total electricity production to be entitled to receive the specific remuneration system. The repetition of this non-compliance is reason for the cancellation of the inscription in the RRRE.

To calculate the energy attributable to the fraction of power entitled to a specific remuneration system, the corresponding energy shall be multiplied by the ratio resulting from dividing the power entitled to a specific remuneration system by the installed power. In order to determine the power entitled to the specific remuneration system of a facility, the value of the power registered for this purpose in the register of the specific remuneration system in operation for said facility shall be taken as the value of the power registered for this purpose in the register of the specific remuneration system in operation for said facility.

For the granting of the specific remuneration system, the conditions, technologies or group of specific facilities that may participate in the competitive competition mechanism shall be established by royal decree. Subsequently, by order of the relevant Minister, with the prior agreement of the Government’s Delegate Committee for Economic Affairs, the remuneration parameters corresponding to the type of reference facilities that are the object of the competitive bidding mechanism shall be established, as well as the terms in which it shall be developed. The granting of this specific remuneration system for existing facilities is regulated in the first transitory provision of RD 413/2014, that establishes that they will be automatically registered on a date to be determined by order of the Minister for Ecological Transition and Demographic Challenge. In any case, it contemplates the possibility of requesting the modification of the inaccuracies that could contain the data of the registry after the referred automatic inscription.

As established in Order IET/1168/2014, of 3 July, the existing facilities were automatically registered in the RRRE on 9 July 2014. In order to determine the information required for automatic registration in the RRRE, the information included in the “Settlement System” at the time of registration was taken into account or, for those facilities not yet included in said System, that of the remuneration pre-allocation register.

Renewable facilities must be registered in the liquidation system of the CNMC. In order for an installation to be registered in said Settlement System, it must be operating and registered in the well-deserved Register.

Payment Factors for Solar Power Plants

The payment system applicable for each plant is based on various criteria considered by the Ministry for Ecological Transition and includes the specific technology used, amount of power produced relative to operating costs, age of the facility and any other differentiating factor deemed necessary to consider in applications of the payment system.

Revenue Order recognizes six types of solar thermal plants: (i) parabolic trough collectors without a storage system, (ii) parabolic trough collectors with a storage system, (iii) central or tower receivers without a storage system, (iv) central or tower receivers with a storage system, (v) linear collectors and (vi) solar-biomass hybrids.

To determine the payment system applicable to each plant, the following factors are considered:
 

Net investment value. This consists of a standard amount per MW for each type of plant, calculated by the method set out in Royal Decree 413/2014, which is the amount invested in the plant and not depreciated as of July 14, 2013.

Useful life of the plant. For solar thermal plants this is 25 years and for photovoltaic plants this is 30 years.

Return on investment. Considering the net asset value determined on the basis of a standard cost per MW built, an amount is set per unit of power, which enables investment costs that cannot be recovered through the pool price to be recouped over the useful life of the plant.

Operating remuneration. An amount is set per unit of power and hour that, added to the pool price, enables the producer to recoup all the plant’s operating and maintenance costs. Operating expenses include the cost of land, electricity, gas and water bills, management, security, corrective and preventive maintenance, representation costs, the Spanish tax on special immovable properties, insurance, applicable generation charges and a generation tax which is equal to 7% of total revenue.

Maximum number of operating hours. A maximum number of hours is set for which each plant type can receive the operating remuneration

Operating threshold. Plants must operate for more than a set number of hours per year to receive the return on investment and operating remuneration.

Minimum operating hours. Plants that cross the operating threshold but operate for fewer hours than the annual minimum hours receive a lower remuneration.
 
Regulatory Periods

Payment criteria are based on prevailing economic conditions in Spain, demand for electricity and reasonable profits for electricity generation activities and can be revised every three or six years. The Royal Decree 413/2014 establishes statutory periods of six years, with the first statutory period running from July 14, 2013 to December 31, 2019 and the second regulatory period beginning in January 2020. Each statutory period is divided into two statutory half-periods of three years.

This “statutory period” mechanism aims to set forth how and when the Ministry for Ecological Transition and Demographic Challenge is entitled to revise the different payment factors used to determine the specific remuneration to be received by the standard facilities.

At the end of each statutory half-period (three years) the Ministry for Ecological Transition and Demographic Challenge may revise (i) the electricity market price estimates and (ii) the adjustment value for electricity market price deviations in the preceding statutory half-period.

Reasonable Rate of Return

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.

The first regulatory period began on January 1, 2013. For this period, the value of the return of the reference rate projects was set, before taxes, as the average secondary market yield for the three months prior to the entry into force of Royal Decree-Law 9/2013, of 12 July, of the 10-year State Obligations increased by 300 basis points. This spread is based on:
 

Appropriate profit for this specific type of renewable electricity generation and electricity generation as a whole, considering the financial condition of the Spanish electricity system and Spanish prevailing economic conditions; and

Borrowing costs for electricity generation companies using renewable energy sources with regulated payment systems, which are efficient and well run, within Europe.
 
The second regulatory period began on January 1, 2020. On July 27, 2018, CNMC (the regulator for the electricity system in Spain) issued a draft proposal for the calculation of the reasonable rate of return for the regulatory period 2020-2025. The reasonable return is no longer calculated by reference to the Spanish government 10-year bonds but 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.

Following the recommendations of the CNMC, the Government adopted the Royal Decree-Law 17/2019, which came into force on November 24, 2020 and was validated by the Permanent Delegation of the Congress on November 27, 2020, and which is aimed to update the reasonable rate of return that applies to standard renewable energy facilities in the period 2020-2025. In accordance with the sole article of this Royal Decree-Law, the reasonable return applicable over the remaining regulatory life of standard facilities, which was used to review and update the remuneration parameters applicable during the second regulatory period, is 7.09%. The measure was intended to create certainty for investors, since it established by means of a regulation with the rank of law the new value of reasonable return for the following regulatory period.

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 24 February were 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, respectively, for the years 2020, 2021 and 2022.
 
The Annex II of the referred Order TED/1717/2020 establishes the remuneration parameters for standard installations applicable to the years 2020, 2021 and 2022: return on investment, number of equivalent operating hours minimum, operating threshold and other remuneration parameters. The parameters applicable to our plants for 2021 are as follows:
 
 
Useful
Life
 
Return on
Investment
2020-2022
(euros/MW)
   
Operating
Remuneration
2021 (euros/GWh)
   
Maximum
Hours
   
Minimum
Hours
   
Operating
Threshold
 
Solaben 2
25 years
   
398,174
     
41,635
     
2,016
     
1,210
     
706
 
Solaben 3
25 years
   
398,174
     
41,635
     
2,016
     
1,210
     
706
 
Solacor 1
25 years
   
398,174
     
41,635
     
2,016
     
1,210
     
706
 
Solacor 2
25 years
   
398,174
     
41,635
     
2,016
     
1,210
     
706
 
PS 10
25 years
   
550,263
     
63,907
     
1,848
     
1,109
     
647
 
PS 20
25 years
   
407,269
     
58,070
     
1,848
     
1,109
     
647
 
Helioenergy 1
25 years
   
393,071
     
41,444
     
2,016
     
1,210
     
706
 
Helioenergy 2
25 years
   
393,071
     
41,444
     
2,016
     
1,210
     
706
 
Helios 1
25 years
   
407,037
     
41,635
     
2,016
     
1,210
     
706
 
Helios 2
25 years
   
407,037
     
41,635
     
2,016
     
1,210
     
706
 
Solnova 1
25 years
   
413,423
     
42,332
     
2,016
     
1,210
     
706
 
Solnova 3
25 years
   
413,423
     
42,332
     
2,016
     
1,210
     
706
 
Solnova 4
25 years
   
413,423
     
42,332
     
2,016
     
1,210
     
706
 
Solaben 1
25 years
   
403,599
     
41,838
     
2,016
     
1,210
     
706
 
Solaben 6
25 years
   
403,599
     
41,838
     
2,016
     
1,210
     
706
 
Seville PV
30 years
   
709,200
     
28,982
     
2,061
     
1,237
     
721
 

Access Fee

Royal Decree-law 14/2010 was passed in order to eliminate the shortfalls between electricity system revenues and costs, referred to as the tariff deficit in the electricity sector.

The First Transitional Provision of Royal Decree-law 14/2010 provided that the owners of electricity production facilities pay a fee for access to the grid to the transmission and distribution companies (this access previously having been provided at no cost) from January 1, 2011. During the interim period, the access fee payable is: (i) calculated at €0.5 per MWh delivered to the network or (ii) any other amount that the Ministry of Ecological Transition and Demographic Challenge establishes.

Royal Decree 1544/2011 implemented the Sole Transitional Provision of Royal Decree 14/2010 and confirmed the interim access fee imposed on electricity producers (€0.5 per MWh), subject to the adoption of a final method for calculating the access fee.

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 combat the problem of the 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, 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 preliminary ruling is expected to be resolved by the Court of Justice of the EU in March 2021. Additionally, the Spanish Parliament has officially proposed an amendment to Law 15/2012 to include a permanent exemption of the electricity sales tax. In case of positive ruling by the Supreme Court of the EU declaring the non-conformity of this tax to EU legislation or approval of a permanent exemption of this tax by the Spanish Parliament, the electricity sales tax could be revoked. In any case, in this situation we expect that the remuneration received by our assets in Spain would be adjusted for the same amount, as a result we do not expect any impact.

Tax Incentive of Accelerated Depreciation of New Assets

Under provisions of the Spanish Corporate Income Tax Act, tax-free depreciation is permitted on investments in new material assets and investment properties used for economic activities acquired between January 1, 2009 and March 31, 2012. Taxpayers who made investments during such period and have amounts pending to be deducted for this concept may apply such amounts with certain limitations.

Taxpayers who made investments from March 31, 2012 through March 31, 2015 in new material assets and investment properties used for economic activities are permitted to take accelerated depreciation for those assets subject to certain limitations. The accelerated depreciation is permitted if:


40% of the tax base before the amortization or depreciation and before the offset of tax loss carryforwards for taxpayers (subject to requirements to keep up employment levels); or


20% of the tax base before the amortization or depreciation and before the offset of tax loss carryforwards for taxpayers (without employment requirements).

Most of the investment in our Spanish assets was undertaken within the regime that applied between January 1, 2009 and March 31, 2012.

These limitations do not apply in respect of companies that meet the requirements set forth in article 108.1 of the Spanish Corporate Income Tax Act related to the special rules for enterprises of a reduced size.

C.
Organizational Structure

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


Notes:—
(1) Atlantica Sustainable Infrastructure plc directly holds one share in Palmucho and 10 shares in each of Quadra 1 and Quadra 2
(2) ATIS directly holds one share in each of Atlantica Peru S.A. (AP), ATN S.A. and ATS S.A.
(3) 30% owned by Itochu, a Japanese company
(4) 13% owned by JGC, a Japanese company
(5) AEC holds 49% of Honaine and Skikda. Valoriza Agua, S.L. holds 25.5% of Honaine and 16.9% of Skikda
(6) 20% of Seville PV owned by Instituto de Diversificacion y Ahorro de la Energia, or IDEA, a Spanish state-owned company
(7) ATN holds a 75% stake in ATS
(8) ATN holds a 25% stake in ATN2
(9) 87.5% owned by Starwood
(10) 29% owned by Industrial Development Corporation, a South African Government company and 20% owned by Kaxu Community Trust
(11) 70% owned by Arroyo Energy
(12) 100% indirectly owned by Arroyo Energy Netherlands II
(13) 70% held by Algonquin
(14) Solar project under development in the U.S.
(15) Solar and wind projects under development
(16) 65% held by financial partners
(17) Solar project 100% owned by Chile Platform
(18) Company expected to acquire Calgary District Heating. Closing of the acquisition is subject to conditions precedent and regulatory approvals

D.
Property, Plant and Equipment

See “Item 4.B—Business Overview.”

ITEM 4A.
UNRESOLVED STAFF COMMENTS

Not applicable.

ITEM 5.
OPERATING AND FINANCIAL REVIEW AND PROSPECTS

The following discussion should be read together with, and is qualified in its entirety by reference to, our Annual Consolidated Financial Statements. The following discussion contains forward-looking statements that reflect our plans, estimates and beliefs, which are based on assumptions we believe to be reasonable. Our actual results could differ materially from those discussed in these forward-looking statements as a result of various factors, including those set forth under “Item 3.D—Risk Factors” and elsewhere in this annual report.

A.
Operating Results

Overview

We are a sustainable infrastructure company with a majority of our business in renewable energy assets. We complement our portfolio of renewable assets with storage, efficient natural gas 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.

As of the date of this annual report, we own or have an interest in a portfolio of diversified assets in terms of business sector and geographic footprint. Our portfolio consists of 28 assets with 1,591 MW of aggregate renewable energy installed generation capacity (of which approximately 90% is solar), representing 74.3% out of our total revenue, 343 MW of efficient natural gas-fired power generation capacity, 1,166 miles of electric transmission lines and 17.5 M ft3 per day of water desalination.

We currently own and manage operating facilities in North America (United States, Canada and Mexico), South America (Peru, Chile and Uruguay) and EMEA (Spain, Algeria and South Africa). We intend to expand our portfolio, maintaining North America, South America and Europe as our core geographies.

Our assets generally have contracted revenue (regulated revenue in the case of our Spanish assets and one transmission line in Chile). We are focused on long-life facilities as well as long-term agreements that we expect to produce stable, long-term cash flows. As of December 31, 2020, our assets had a weighted average remaining contract life of approximately 17 years. Most of the assets we own, or in which we have an interest have project-finance agreements in place. We intend to grow our cash available for distribution and our dividend to shareholders through organic growth and by acquiring new assets and/or businesses where revenue may not be fully contracted.

We intend to take advantage of, and leverage our growth strategy on, favorable trends in clean power generation, energy scarcity and the focus on the reduction of carbon emissions. Our portfolio of operating assets and our strategy focus on sustainable technology including renewable energy, storage, efficient natural gas, and transmission networks as enablers of a sustainable power generation mix and on water infrastructure. Renewable energy is expected to represent in most markets the majority of new investments in the power sector, according to Bloomberg New Energy Finance 2020, approximately 68% of the world’s power generation by 2050 is expected to come from renewable energy sources, which indicates that renewable energy is becoming mainstream. Global installed capacity is expected to shift from 56% fossil fuels today to approximately two-thirds renewables by 2050. A 14-terawatt expansion of generating capacity is estimated to require approximately $15.1 trillion of new investment between now and 2050 – of which approximately 73% is expected to go to renewables. Another approximately $1 trillion of investment is expected in batteries along with an estimated $14 trillion in expected to go to transmission and distribution during that same period. We believe regions will need to complement investments in renewable energy with investments in storage, efficient natural gas and in transmission networks. We believe that we are well positioned to benefit from the expected transition towards a more sustainable power generation mix. In addition, we believe that water is going to be the next frontier in a transition towards a more sustainable world. New sources of water are needed worldwide, and water desalination and water transportation infrastructure should help make that possible. We currently participate in three water desalination plants with a total capacity of 17.5 million cubic feet per day.

We believe we can achieve organic growth through the optimization of the existing portfolio, escalation factors in many of our assets and the expansion of current assets, particularly our transmission lines, to which new assets can be connected. We currently own three transmission lines in Peru and four in Chile. We believe that current regulations in Peru and Chile provide a growth opportunity by expanding transmission lines to connect new clients. Additionally, we should have repowering opportunities in certain existing renewable energy assets.

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 have also entered into and intend to enter into agreements or partnerships with developers and asset owners to acquire assets. We also invest directly and through investment vehicles with partners in assets under development or construction.

We have signed a ROFO agreement with AAGES, a joint venture designed to invest in the development and construction of contracted clean energy and water infrastructure contracted assets, created by Algonquin, a North American diversified generation, transmission and distribution utility company that owns a 44.2% stake in our capital stock

With this business model, 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 and through the acquisition of assets. Pursuant to our cash dividend policy, we intend to pay a cash dividend each quarter to holders of our shares.

Significant Events in 2020

COVID-19 Pandemic

The outbreak of the COVID-19 coronavirus disease (“COVID-19”) declared a pandemic by the World Health Organization in March 2020 continues to spread in our key markets, which have already experienced several waves of the virus. The COVID-19 virus continues to evolve rapidly, and its impact is still uncertain and subject to change. In a bid to combat the spread of the virus, governmental authorities have both taken and recommended a wide variety of measures, including lockdowns and travel restrictions. We have reinforced safety measures at all our assets while still continuing to provide a reliable service to our clients. Since March 2020, we have implemented the use of additional personal protection equipment, reinforced access control to our plants, reduced contact between employees, changed shift and, tested employees. We have also identified and isolated cases and potential cases together with their close contacts and taken additional measures to increase safety procedures for our employees and operation and maintenance suppliers’ employees working at our assets. We have also purchased additional spare parts and equipment required for operations, to safeguard against any potential supply chain disruptions. Although we have not experienced any material impacts, we are seeing some delays in certain maintenance activities. Furthermore, we have adopted additional precautionary measures intended to mitigate potential risks to our employees, including temporarily requiring employees when possible to work remotely in geographies with higher incidence, and suspending all non-essential travel. We have also reinforced our physical and cyber-security measures. We have implemented protocols to decide which offices to keep open and under what limitations, depending on the number of cases and other health indicators in each specific region. We continue to monitor the situation closely at all assets and offices and are ready to take additional action if and when required.

To date, we have not experienced material operational or financial impacts as a result of COVID-19. We have not experienced any disruptions in availability or production in our assets due to COVID-19. Our businesses are considered an essential and critical activity in all our geographies, so we have continued operating our assets even in those countries where economic activity has been limited only to essential business for a certain period of time. In addition, our assets generally have long-term contracts or regulated revenue.

Despite all the above, we cannot guarantee that our operations and financial situation will remain unaffected by the COVID-19 outbreak. (see “Part II—Item 1.A —Risk Factors—Risks Related to the COVID-19 Pandemic”).

Conclusion of the Special Committee

On March 23, 2020 we announced that our special committee concluded the review of the strategic alternatives by reaffirming our current strategy.

Acquisitions during the year

On April 3, 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. The first investment was the acquisition of a 55 MW solar PV plant in an area with excellent solar resource (Chile PV 1). This asset, has been in operation since 2016, demonstrating a good operating track record during that period while selling its production in the Chilean power market. Our initial contribution was approximately $4 million. On January 6, 2021 we also closed our second investment through the platform with the acquisition of Chile PV 2, a 40 MW PV plant. This asset started commercial operation in 2017 and its revenue is partially contracted. Total equity investment in this new asset was approximately $5.0 million. We have concluded that we have control over these assets, and we are fully consolidating it since each acquisition date. The platform intends to make further investments in renewable energy in Chile and sign PPAs with creditworthy off-takers.

On August 17, 2020 we closed the acquisition of the Liberty ownership interest in Solana. Liberty was the tax equity investor in Solana. Total equity investment is expected to be up to $290 million of which $272 million has already been paid. The total price includes a deferred payment and a performance earn-out based on the average annual net production of the asset in the four calendar years with the highest annual net production during the five calendar years from 2020 through 2024.

In October 2020 we reached an agreement to acquire Calgary District Heating, a district heating asset in Canada for a total equity investment of approximately $20 million. Calgary District Heating has been in operation since 2010 and represents our first investment in this sector, a sector which has been recognized by the UN Environment Program as being a key measure for cities to reduce their emissions. The asset provides heating services to a diverse range of government, institutional and commercial customers in the city of Calgary. It has availability-based revenue with inflation indexation and 20 years of weighted average contract life. Contracted capacity and volume payments represent approximately 80% of total revenue. Closing is expected by mid-2021 subject to customary conditions precedent and regulatory approvals.

In December 2020 we reached an agreement with Algonquin to acquire La Sierpe, a 20 MW solar asset in Colombia for a total equity investment of approximately $20 million. Closing is expected to occur after the asset reaches commercial operation, currently expected to occur by mid-2021. Closing is subject to customary conditions precedent and regulatory approvals. Additionally, we agreed to potentially co-invest with Algonquin in additional solar plants in Colombia with a combined capacity of approximately 30 MW to be developed and built by AAGES.

In December 2020, we reached an agreement to acquire 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 ISO. It has PPAs signed with three investment grade offtakers, with a 19-year average contract life. Closing is subject to customary regulatory approvals and is expected to occur in the first half of 2021. The total investment is expected to be approximately $170 million, including approximately $130 million for the equity and $40 million expected to be invested in reducing project debt.

In January 2021 we reached an agreement to increase our equity stake from 15% up to 100% in Rioglass, a multinational manufacturer of solar components. We have closed the acquisition of a 42.5% equity stake, for which we paid $7 million. In addition, we have an option to acquire the remaining 42.5% in the same conditions until September 2021, and after that date the seller has an option to sell the 42.5% also in the same conditions. We intend to find partners to co-invest in the company, as such we expect to classify the investment as held for sale in our consolidated financial statements.

In October 2018, we reached an agreement to acquire PTS, a natural gas transportation platform located in Mexico, close to ACT. PTS has a service agreement signed in October 2017, which is a “take-or-pay” 11-year term contract starting in 2020. We initially acquired a 5% ownership in the project and have an agreement to acquire an additional 65% stake subject to the asset entering into commercial operation, non-recourse project financing being closed and final approvals and customary conditions, including the absence of material adverse effects. Our partner in this asset is also negotiating to sell part of its business, which may include the company that provides operation and maintenance services to PTS. This sale may require change of control waivers and may make the closing of the acquisition more difficult. Additionally, our partner has proposed a number of modifications to the project and the financing agreements. We are currently monitoring the situation in order to decide if we will proceed with the investment or not. We therefore cannot guarantee that we will close this acquisition or that closing will occur on the terms originally agreed.

Corporate Financing Activities

On April 1, 2020 we closed the secured 2020 Green Private Placement for €290 million (approximately $354 million). The private placement accrues an annual rate of 1.96%, payable quarterly and matures in June 2026. Net proceeds were primarily used to repay the Note Issuance Facility 2017.

On July 8, 2020, we entered into the Note Issuance Facility 2020, a senior unsecured financing with Lucid Agency Services Limited, as agent, and a group of funds managed by Westbourne Capital as purchasers of the notes issued thereunder for a total amount of approximately $171 million which is denominated in euros (€140 million). The notes under the Note Issuance Facility 2020 were issued on August 12, 2020 and have a maturity of seven years from the closing date. We expect to use the proceeds from the Note Issuance Facility 2020 to finance acquisitions and for general corporate purposes.

On July 17, 2020, we issued $100 million aggregate principal amount of 4.00% Green Exchangeable Notes due 2025. On July 29, 2020, we issued additional $15 million aggregate principal amount of the Green Exchangeable Notes. The notes mature on July 15, 2025. 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 our election, into ordinary shares of Atlantica, cash or a combination of both. The exchange rate is subject to adjustment upon the occurrence of certain events. The proceeds from the Green Exchangeable Notes were used to finance the acquisition of new or existing assets or projects which meet certain eligibility criteria in accordance with our Green Finance Framework.

On December 11, 2020 we 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. Additionally, Algonquin purchased 4,020,860 ordinary shares in a private placement in order to maintain its equity interest in the Company. The private placement closed on January 7, 2021. Gross proceeds of the public offering and the private placement were approximately $300 million, which we intend to use to finance growth opportunities and for general corporate purposes after deducting underwriting discounts and commissions and offering expenses

Project Financing Activities

On April 8, 2020, Logrosan Solar Inversiones, S.A, the subsidiary-holding company of Solaben 1 & 6 and Solaben 2 & 3 entered into the Green Project Finance, a green project financing euro-denominated agreement with ING Bank, B.V. and Banco Santander S.A. The lenders of the new facility have no recourse to Atlantica at the corporate level. After considering transaction costs and reserves, the Green Project Finance resulted in a net recap of $143 million that was used to finance new investments in renewable assets. The Green Project Finance was issued in compliance with the 2018 Green Loan Principles and have a Second Party Opinion delivered by Sustainalytics.

On July 10, 2020, we entered into a non-recourse project debt refinancing of Helioenergy, one of the Spanish solar assets, by adding a new long dated tranche of debt from an institutional investor. The new tranche bears interest at a fixed rate of approximately 3% per annum and has a 15-year maturity. After transaction costs, net refinancing proceeds (net “recap”) were approximately $43 million.

In addition, on July 14, 2020, we entered into a non-recourse project debt financing for approximately €326 million in relation to Helios, pursuant to a monoline guarantee. Lenders are institutional investors. The new debt has a 17-year maturity and bears interest at a rate of approximately 2% per annum. The proceeds were used to repay the outstanding project debt of approximately €250 million and cancel legacy interest rate swaps. After transaction costs and the cancelation of legacy swaps, net refinancing proceeds (net “recap”) were approximately $30 million.

Factors Affecting the Comparability of Our Results of Operations

Acquisitions

The results of operations of ATN Expansion 2 have been fully consolidated since October 2019, the results of operations of Tenes have been fully consolidated since May 2020 and the results of operations of Chile PV 1 have been fully consolidated since April 2020. In addition, Monterrey has been recorded under the equity method since August 2019 and Tenes was recorded under the equity method since January 2019 until May 2020, when we gained control over the asset and started to fully consolidate it.

In addition, in August 2020, we acquired out tax equity investor interest in Solana. Despite Liberty’s investment was in shares, it did not qualify as equity and was recorded as liability under IFRS. The acquisition resulted in a non-cash financial gain of approximately $145 million which arose from the difference between the total purchase price and the liability previously recorded. The gain was recognized in the line “Other Financial Income”.

Impairment

In 2020, the availability at the Solana storage system was lower than expected due to certain leaks identified in this system in the first quarter. Improvements and equipment replacements are required over time, which have impacted production in 2020 and will continue to impact production in 2021, with the exact scope and timing of the works subject to review. Based on our preliminary plan, we expect that we will need to replace some elements of the storage system, which have been 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 has a cash repair reserve account funded with approximately $54 million that we expect to partially or totally use for this purpose.

Additionally, 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, 2020 we recorded a $26.6 million impairment provision in ACT following a worsening of its client’s credit risk metrics, impairment was recognized in the line “Depreciation, amortization, and impairment charges”. We recorded a reversal of the impairment provision for $3.2 million for the year ended December 31, 2019.

In addition, in 2020 we accounted for an impairment reversal in our wind assets in Uruguay for approximately $18.8 million in Cadonal and Palmatir (see Note 6 to our Annual Consolidated Financial Statements). The reversal was recognized in the line “Depreciation, amortization, and impairment charges”.

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 (see Note 6 to our Annual Consolidated Financial Statements). This change in the estimated useful life is accounted for as a change in accounting estimates in accordance with IAS 8, Accounting Policies, Changes in Accounting Estimates and Errors. As a result, we recorded an approximately $23.2 million increase in “Depreciation and amortization and impairment charges” in 2020 compared with the previous year.

Project debt refinancing

On July 14, 2020, as previously explained, we entered into a non-recourse project debt financing in Helios 1 & 2 for approximately €326 million. The notes were issued on July 23, 2020 and have a 17-year maturity. Under this refinancing we canceled the interest rate swaps hedging the old debt, which caused the reclassification from equity to the income statement of the accumulated impact of the mark-to-market of such derivatives for approximately $44.7 million. In addition, we recorded a $28.4 million loss for the difference between the accounting value and nominal value of the old debt. In total, we recorded a one-time loss of approximately $73.1 million in the third quarter of 2020, mostly non-cash, that is recognized in “Other financial expenses”.

Significant Trends Affecting Results of Operations

Acquisitions

If the acquisitions recently announced close as expected after the fulfillment of conditions precedent and obtain all required regulatory approvals, including Coso, Calgary District Heating and La Sierpe we expect these assets to impact our results of operations in 2021 and upcoming years, once we start consolidating them upon closing. See “Item 4—Information on the Company—Acquisitions—2020 and 2021 acquisitions”.

Solar, wind and geothermal resources

The availability of solar, wind and, once we close the Coso acquisition, 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. To the extent the solar, wind and geothermal resources are not available at expected levels, it could have 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 such acquisitions. Fluctuations in capital markets may affect our ability to access to such capital through debt or equity financings.

Exchange rates

Our functional currency is the U.S. dollar, as most of our revenue and expenses are denominated or linked to U.S. dollars. All our companies located in North America 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 Spain have their revenue and expenses denominated in euros, and Kaxu, our solar plant in South Africa, has its revenue and expenses denominated in South African rand. Financing of projects 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 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 Spanish assets. We hedge the exchange rate for the distributions from our Spanish assets 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. Impacts associated with fluctuations in foreign currency are discussed in more detail under “Item 3—Quantitative and Qualitative Disclosure about Market Risk—Foreign exchange risk”. Fluctuations in the value of the South African rand in relation to the U.S. dollar may also affect our operating results.

Interest rates

We incur significant indebtedness at the corporate and asset level. The interest rate risk arises mainly from indebtedness at variable interest rates. To mitigate interest rate risk, we primarily use long-term interest rate swaps and interest rate options which, in exchange for a fee, offer protection against a rise in interest rates. As of December 31, 2020, approximately 92% of our project debt and approximately 100% of our corporate debt either has fixed interest rates or has been hedged with swaps or caps. Nevertheless, our results of operations can be affected by changes in interest rates with respect to the unhedged portion of our indebtedness that bears interest at floating rates, which typically bear a spread over EURIBOR or LIBOR.

Key Financial Measures

Our revenue and Adjusted EBITDA by geography and business sector for the years ended December 31, 2020, 2019 and 2018 are set forth in the following tables:

Revenue by geography
 
Year ended December 31,
 
 
2020
 
2019
 
2018
 
 
$ in
millions
 
% of
revenue
 
$ in
millions
 
% of
revenue
 
$ in
millions
 
% of
revenue
 
North America
 
$
330.9
     
32.6
%
 
$
333.0
     
32.9
%
 
$
357.2
     
34.2
%
South America
   
151.5
     
15.0
%
   
142.2
     
14.1
%
   
123.2
     
11.8
%
EMEA
   
530.9
     
52.4
%
   
536.3
     
53.0
%
   
563.4
     
54.0
%
Total revenue
 
$
1,013.3
     
100.0
%
 
$
1,011.5
     
100.0
%
 
$
1,043.8
     
100
%

Revenue by business sector
 
Year ended December 31,
 
 
2020
 
2019
 
2018
 
 
$ in
millions
 
% of
revenue
 
$ in
millions
 
% of
revenue
 
$ in
millions
 
% of
revenue
 
Renewable Energy
 
$
753.1
     
74.3
%
 
$
761.1
     
75.2
%
 
$
793.5
     
76.0
%
Efficient Natural Gas
   
111.0
     
11.0
%
   
122.3
     
12.1
%
   
130.8
     
12.5
%
Electric Transmission
   
106.1
     
10.5
%
   
103.5
     
10.2
%
   
96.0
     
9.2
%
Water
   
43.1
     
4.2
%
   
24.6
     
2.4
%
   
23.5
     
2.3
%
Total revenue
 
$
1,013.3
     
100.0
%
 
$
1,011.5
     
100.0
%
 
$
1,043.8
     
100
%

Adjusted EBITDA by geography
 
Year ended December 31,
 
 
2020
 
2019
 
2018
 
 
$ in
millions
 
% of
revenue
 
$ in
millions
 
% of
revenue
 
$ in
millions
 
% of
revenue
 
North America
 
$
272.9
     
82.5
%
 
$
305.1
     
91.6
%
 
$
308.8
     
86.4
%
South America
   
120.0
     
79.2
%
   
115.3
     
81.1
%
   
100.2
     
81.3
%
EMEA
   
388.7
     
73.1
%
   
390.8
     
72.9
%
   
441.6
     
78.4
%
Adjusted EBITDA(1)
 
$
781.6
     
77.1
%
 
$
811.2
     
80.2
%
 
$
850.6
     
81.5
%

Adjusted EBITDA by business sector

 
Year ended December 31,
 
 
2020
 
2019
 
2018
 
 
$ in
millions
 
% of
revenue
 
$ in
millions
 
% of
revenue
 
$ in
millions
 
% of
revenue
 
Renewable Energy
 
$
575.6
   
$
76.4
%
 
$
603.7
   
$
79.3
%
 
$
664.4
     
83.7
%
Efficient Natural Gas
   
97.9
     
88.2
%
   
107.5
     
87.9
%
   
93.9
     
71.8
%
Electric Transmission
   
84.6
     
79.7
%
   
85.6
     
82.7
%
   
78.4
     
81.7
%
Water
   
23.5
     
54.5
%
   
14.4
     
58.5
%
   
13.9
     
59.1
%
Adjusted EBITDA(1)
 
$
781.6
   
$
77.1
%
 
$
811.2
   
$
80.2
%
 
$
850.6
     
81.5
%

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 from continued operations, income tax, share of profit/(loss) of associates carried under the equity method, finance expense net, depreciation, amortization and impairment charges of entities included in the Annual Consolidated Financial Statements. 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

   
Year ended December 31,
 
   
2020
   
2019
   
2018
 
   
($ in millions)
 
Profit/(loss) for the year attributable to the parent company
 
$
11.9
   
$
62.1
   
$
41.6
 
Profit/(loss) attributable to non-controlling interest from continued operations
   
4.9
     
12.5
     
13.7
 
Income tax expense
   
24.9
     
30.9
     
42.6
 
Share of (profit)/loss of associates carried under the equity method
   
(0.5
)
   
(7.5
)
   
(5.2
)
Financial expense, net
   
331.8
     
402.3
     
395.2
 
Operating profit /(loss)
 
$
373.0
   
$
500.4
   
$
487.9
 
Depreciation, amortization and impairment charges
   
408.6
     
310.8
     
362.7
 
 Adjusted EBITDA
 
$
781.6
   
$
811.2
   
$
850.6
 

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

Reconciliation of net cash generated by operating activities to Adjusted EBITDA

 
Year ended December 31,
 
 
2020
   
2019
   
2018
 
 
($ in millions)
 
Net cash flow provided by operating activities
 
$
438.2
   
$
363.5
   
$
401.0
 
Net interest /taxes paid
   
287.2
     
299.5
     
333.5
 
Variations in working capital
   
33.2
     
113.4
     
18.4
 
Other non-cash adjustments and other
   
23.0
     
34.8
     
97.7
 
 Adjusted EBITDA
 
$
781.6
   
$
811.2
   
$
850.6
 

Operational Metrics

In addition to the factors described above, we closely monitor the following key drivers of our business sectors’ performance to plan for our needs, and to adjust our expectations, financial budgets and forecasts appropriately.


MW in operation in the case of Renewable Energy and Efficient Natural Gas assets, miles in operation in the case of Electric Transmission and Mft3 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 assets provides information about the performance of these assets.
 

Availability in the case of our Efficient Natural Gas assets, Electric Transmission and Water assets also provides information on the performance of the assets. In these business segments revenues are based on availability, which is the time during which the asset was available to our client totally or partially divided by contracted availability or budgeted availability, as applicable.
 
   
As of and for the year ended December 31,
 
   
2020
   
2019
   
2018
 
Renewable Energy
                 
MW in operation(1)
   
1,551
     
1,496
     
1,496
 
GWh produced(2)
   
3,244
     
3,236
     
3,058
 
Efficient Natural Gas
                       
MW in operation(3)
   
343
     
343
     
300
 
GWh produced(4)
   
2,574
     
2,090
     
2,318
 
Availability (%)(4)
   
102.1
%
   
95.0
%
   
99.8
%
Electric Transmission
                       
Miles in operation
   
1,166
     
1,166
     
1,152
 
Availability (%)
   
100.0
%
   
100.0
%
   
99.9
%
Water
                       
Mft3 in operation(1)
   
17.5
     
10.5
     
10.5
 
Availability (%)
   
100.1
%
   
101.2
%
   
102.0
%

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.
(2)
Includes curtailment in wind assets for which we receive compensation
(3)
Includes 43MW corresponding to our 30% share in Monterrey since August 2, 2019
(4)
Major maintenance overhaul held in Q1 and Q2 2019 in ACT, as scheduled, which reduced production and electric availability as per the contract. GWh produced includes 30% of the production from Monterrey since August 2019.

Results of Operations

The table below illustrates our results of operations for the years ended December 31, 2020, 2019 and 2018.

   
Year ended December 31,
 
   
2020
   
2019
   
2018
 
   
$ in millions
 
Revenue
 
$
1,013.3
   
$
1,011.5
   
$
1,043.8
 
Other operating income
   
99.5
     
93.8
     
132.5
 
Employee benefit expenses
   
(54.4
)
   
(32.2
)
   
(15.1
)
Depreciation, amortization and impairment charges
   
(408.6
)
   
(310.8
)
   
(362.7
)
Other operating expenses
   
(276.7
)
   
(261.8
)
   
(310.6
)
Operating profit/(loss)
 
$
373.1
   
$
500.4
   
$
487.9
 
Financial income
   
7.1
     
4.1
     
36.4
 
Financial expense
   
(378.4
)
   
(408.0
)
   
(425.0
)
Net exchange differences
   
(1.4
)
   
2.7
     
1.6
 
Other financial income/(expense), net
   
40.9
     
(1.1
)
   
(8.2
)
Financial expense, net
 
$
(331.8