ALGONQUIN POWER & UTILITIES CORP. Form 40-F/A Filed 2023-03-21

UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

FORM 40-F/A

(Amendment No. 1)


☐			REGISTRATION STATEMENT PURSUANT TO SECTION 12 OF THE SECURITIES EXCHANGE ACT OF 1934 OR
☒			ANNUAL REPORT PURSUANT TO SECTION 13(a) OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934

For the fiscal year ended December 31, 2022 Commission File Number 001-37946

ALGONQUIN POWER & UTILITIES CORP.

(Exact name of Registrant as specified in its charter)

N/A

(Translation of Registrant’s name into English (if applicable))

Canada

(Province or other jurisdiction of incorporation or organization)

4911

(Primary Standard Industrial Classification Code Number (if applicable))

N/A

(I.R.S. Employer Identification Number (if applicable))

354 Davis Road
Oakville, Ontario
L6J 2X1, Canada

(905) 465-4500
(Address and telephone number of Registrant’s principal executive offices)

CT Corporation System
111 Eighth Avenue
New York, New York 10011
(212)894-8940
(Name, address (including zip code) and telephone number (including area code)
of agent for service in the United States)

Securities registered or to be registered pursuant to Section 12(b) of the Act:


Title of each class	Trading Symbol(s)	Name of each exchange on which registered
Common shares, no par value	AQN	The New York Stock Exchange
6.875% Fixed-to-Floating Subordinated Notes - Series 2018-A due October 17, 2078	AQNA	The New York Stock Exchange
6.20% Fixed-to-Floating Subordinated Notes - Series 2019-A due July 1, 2079	AQNB	The New York Stock Exchange
Corporate Units	AQNU	The New York Stock Exchange
Rights to Purchase One Common Share of the Company	N/A	The New York Stock Exchange

Securities registered or to be registered pursuant to Section 12(g) of the Act:

Common Shares, no par value
(Title of Class)

Securities for which there is a reporting obligation pursuant to Section 15(d) of the Act: None

For annual reports indicate by check mark the information filed with this Form:


☒ Annual Information Form			☒ Audited Annual Financial Statements

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:

As of December 31, 2022, there were 683,614,803 Common Shares outstanding.

Indicate by check mark whether the Registrant (1) has filed all reports required to be filed by Section 13 or 15(d) of the Exchange Act 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 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 an emerging growth company as defined in Rule 12b-2 of the Exchange Act.

Emerging growth company ☐

If an emerging growth company that prepares its financial statements in accordance with U.S. GAAP, indicate by check mark if the Registrant has elected not to use the extended transition period for complying with any new or revised financial accounting standards† provided pursuant to Section 13(a) of the Exchange Act.

† The term “new or revised financial accounting standard” refers to any update issued by the Financial Accounting Standards Board to its Accounting Standards Codification after April 5, 2012.

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

If securities are registered pursuant to Section 12(b) of the Act, indicate by check mark whether the financial statements of the registrant included in the filing reflect the correction of an error to previously issued financial statements.

Indicate by check mark whether any of those error corrections are restatements that required a recovery analysis of incentive-based compensation received by any of the registrant’s executive officers during the relevant recovery period pursuant to §240.10D-1(b).

This Annual Report on Form 40-F shall be incorporated by reference into or as an exhibit to, as applicable, the Registrant’s Registration Statements on Form F-3 (File Nos. 333-220059, 333-227246 and 333-263839), Form F-10 (File No. 333-261010) and Form S-8 (File Nos. 333-177418, 333-213648, 333-213650, 333-218810, 333-232012 and 333-238961) under the Securities Act of 1933, as amended.

EXPLANATORY NOTE

This Amendment No. 1 (“Amendment No. 1”) to the annual report on Form 40-F of Algonquin Power & Utilities Corp. (“AQN” or the “Company”), originally filed with the U.S. Securities and Exchange Commission (“SEC”) on March 17, 2023 (the “Previous Form 40-F”), is being filed with the SEC to refile the Management Discussion and Analysis for the fiscal year ended December 31, 2022 (the “MD&A”) to correct the date of the MD&A to March 17, 2023. This Amendment No. 1 also includes new certifications of the Chief Executive Officer and Chief Financial Officer of the Company pursuant to Sections 302 and 906 of the U.S. Sarbanes-Oxley Act of 2002.

Other than as discussed above, all information in this Amendment No. 1 is unchanged from the Previous Form 40-F. For the convenience of readers, the Company included in this Amendment No. 1 all information set forth in the Previous Form 40-F and all exhibits thereto.

ANNUAL INFORMATION FORM

The Annual Information Form (the “AIF”) of the Company for the fiscal year ended December 31, 2022 is filed as Exhibit 99.1 to this annual report on Form 40-F. All capitalized terms used herein but not otherwise defined herein shall have the meanings given to such terms in the AIF.

AUDITED ANNUAL FINANCIAL STATEMENTS

The Audited Annual Consolidated Financial Statements of AQN for the fiscal year ended December 31, 2022 (the “Consolidated Financial Statements”) are filed as Exhibit 99.2 to this annual report on Form 40-F.

MANAGEMENT’S DISCUSSION AND ANALYSIS

The MD&A is filed as Exhibit 99.3 to this annual report on Form 40-F.

DISCLOSURE CONTROLS AND PROCEDURES

The information provided under the heading “Disclosure Controls and Procedures” in the MD&A, filed as Exhibit 99.3 to this annual report on Form 40-F, is incorporated by reference herein.

INTERNAL CONTROL OVER FINANCIAL REPORTING

A. Management’s report on internal control over financial reporting

The information provided under the headings “Disclosure Controls and Procedures—Management Report on Internal Controls over Financial Reporting” and “Disclosure Controls and Procedures—Inherent Limitations on Effectiveness of Controls” in the MD&A, filed as Exhibit 99.3 to this annual report on Form 40-F, is incorporated by reference herein.

B. Auditor’s attestation report on internal control over financial reporting

Ernst & Young LLP (PCAOB ID#: 1263), the independent registered public accounting firm of AQN, which audited the consolidated financial statements of AQN for the year ended December 31, 2022, has also issued an attestation report on the effectiveness of AQN’s internal control over financial reporting as of December 31, 2022. The attestation report is provided in Exhibit 99.2 to this annual report on Form 40-F and is incorporated by reference herein.

C. Changes in internal control over financial reporting

The information provided under the heading “Disclosure Controls and Procedures—Changes in Internal Controls over Financial Reporting” in the MD&A, filed as Exhibit 99.3 to this annual report on Form 40-F, is incorporated by reference herein.

AUDIT COMMITTEE FINANCIAL EXPERTS

AQN’s board of directors has determined that it has one audit committee financial expert serving on its audit committee. Dilek Samil has been determined to be such audit committee financial expert and is “independent” as set forth in the Canadian National Instrument 58-101 Disclosure of Corporate Governance Practices and Rule 10A-3 of the U.S. Securities Exchange Act of 1934, as amended (the “Exchange Act”). The SEC has indicated that the designation as an audit committee financial expert does not make a person an “expert” for any purpose, impose any duties, obligations or liability on such persons that are greater than those imposed on members of the audit committee and board of directors who do not carry this designation or affect the duties, obligations or liability of any other member of the audit committee or board of directors.

CODE OF ETHICS

AQN has adopted a code of business conduct and ethics (the “Code of Conduct”) that applies to all employees and officers, including its Chief Executive Officer and Chief Financial Officer. The Code of Conduct is available without charge to any shareholder upon request to Brian Chin, Telephone: (905) 465-4450, E-mail: InvestorRelations@APUCorp.com, Algonquin Power & Utilities Corp., 354 Davis Road, Oakville, Ontario L6J 2X1.

PRINCIPAL ACCOUNTANT FEES AND SERVICES

The information provided under the heading “Pre-Approval Policies and Procedures” in the AIF, filed as Exhibit 99.1 to this annual report on Form 40-F, is incorporated by reference herein. All audit services, audit-related services, tax services, and other services provided for the years ended December 31, 2021 and 2022 were pre-approved by the audit committee.

OFF-BALANCE SHEET ARRANGEMENTS

AQN’s off-balance sheet arrangements consist of obligations under equity capital contribution agreements and guarantees for certain development projects which the Company does not have sole control. These instruments provide financial assurance necessary for the continued development and construction of the projects. The Company also pledged shares in Atlantica Sustainable Infrastructure plc (“Atlantica”) as collateral to a secured credit facility issued by the Company’s equity-method investee. For a discussion of these arrangements, refer to the information in note 8 and note 17 to the Consolidated Financial Statements, filed as Exhibit 99.2 to this annual report on Form 40-F and incorporated by reference herein, and the information under the heading “Enterprise Risk Management - Operational Risk Management - Joint Venture Investment Risk” in the MD&A, filed as Exhibit 99.3 to this annual report on Form 40-F and incorporated by reference herein.

CONTRACTUAL OBLIGATIONS

The information provided under the heading “Contractual Obligations” in the MD&A, filed as Exhibit 99.3 to this annual report on Form 40-F, is incorporated by reference herein.

NON-GAAP FINANCIAL MEASURES

The MD&A contains financial measures that are not recognized measures under U.S. generally accepted accounting principles (“U.S. GAAP”). Such terms include: “Adjusted Net Earnings”, “Adjusted Net Earnings per Common Share”, “Adjusted Earnings Before Interest, Taxes, Depreciation and Amortization” (“Adjusted EBITDA”), “Adjusted Funds from Operations”, “Net Energy Sales”, “Net Utility Sales” and “Divisional Operating Profit”. There is no standardized measure of these terms and, consequently, the Company’s method of calculating these measures may differ from methods used by other companies and therefore may not be comparable to similar measures presented by other companies. A calculation and analysis of “Adjusted Net Earnings”, “Adjusted Net Earnings per common share”, “Adjusted EBITDA”, “Adjusted Funds from Operations”, “Net Energy Sales”, “Net Utility Sales”, and “Divisional Operating Profit”, including a reconciliation to the U.S. GAAP equivalent, can be found in the MD&A under the headings “Caution Concerning Non-GAAP Financial Measures”, “Non-GAAP Financial Measures”, “Renewable Energy Group—2022 Renewable Energy Group Operating Results”, and “Regulated Services Group—2022 Regulated Services Group Operating Results”.

without unreasonable effort. This is due to the inherent difficulty of forecasting the timing or amount of various events that have not yet occurred, are out of AQN’s control and/or cannot be reasonably predicted, and that would impact the most directly comparable forward-looking U.S. GAAP financial measure. For these same reasons, AQN is unable to address the probable significance of the unavailable information. Forward-looking non-GAAP financial measures may vary materially from the corresponding U.S. GAAP financial measures.

The MD&A is attached hereto as Exhibit 99.3 and is incorporated herein by reference and is also available on EDGAR at www.sec.gov and SEDAR at www.sedar.com.

CAUTION CONCERNING FORWARD LOOKING STATEMENTS

This document, which includes the information set forth in the exhibits hereto, contains statements that constitute “forward-looking information” within the meaning of applicable securities laws in each of the provinces and territories of Canada and the respective policies, regulations and rules under such laws and/or “forward-looking statements” within the meaning of the U.S. Private Securities Litigation Reform Act of 1995 (collectively, “forward-looking information”). The words “anticipates”, “believes”, “budget”, “could”, “estimates”, “expects”, “forecasts”, “intends”, “may”, “might”, “plans”, “projects”, “schedule”, “should”, “will”, “would”, “aims,” “seeks”, strives” (and grammatical variations of such terms) and similar expressions are often intended to identify forward-looking information, although not all forward-looking information contains these identifying words. The forward-looking information contained herein is subject to risks, uncertainties and other factors that could cause actual results to differ materially from historical results or results anticipated by the forward-looking information.

The sections entitled “Caution Concerning Forward-Looking Statements and Forward-Looking Information” set forth in each of Exhibits 99.1 and 99.3 hereto are incorporated by reference herein. You should carefully review such information for examples of specific forward-looking information included and incorporated in this document, for examples of factors or assumptions reflected in the forward-looking information and for a summary of risks, uncertainties and other factors that could cause actual results to differ materially from historical or anticipated results.

Forward-looking information contained herein (including any financial outlook) is provided for the purposes of assisting the reader in understanding the Company and its business, operations, risks, financial performance, financial position and cash flows as at and for the periods indicated and to present information about management’s current expectations and plans relating to the future and the reader is cautioned that such information may not be appropriate for other purposes. Forward-looking information contained herein is made as of the date of this document and based on the plans, beliefs, estimates, projections, expectations, opinions and assumptions of management on the date hereof. There can be no assurance that forward-looking information will prove to be accurate, as actual results and future events could differ materially from those anticipated in such forward-looking information. Accordingly, readers should not place undue reliance on forward-looking information. While subsequent events and developments may cause the Company’s views to change, the Company disclaims any obligation to update any forward-looking information or to explain any material difference between subsequent actual events and such forward-looking information, except to the extent required by applicable law. All forward-looking information contained herein is qualified by these cautionary statements.

All forward-looking information is given pursuant to the “safe harbor” provisions of applicable securities legislation.

IDENTIFICATION OF THE AUDIT COMMITTEE

AQN has a standing audit committee of its board of directors established in accordance with Section 3(a)(58)(A) of the Exchange Act. The information provided under the heading “Audit Committee” identifying AQN’s audit committee and confirming the independence of the audit committee in the AIF, filed as Exhibit 99.1 to this annual report on Form 40-F, is incorporated by reference herein.

INTERACTIVE DATA FILE

The required disclosure for the fiscal year ended December 31, 2022 is filed as Exhibit 101 to this annual report on Form 40-F.

MINE SAFETY DISCLOSURE

Not applicable.

COMPARISON OF NYSE CORPORATE GOVERNANCE RULES

AQN is subject to corporate governance requirements prescribed under applicable Canadian corporate governance practices, including the rules of the Toronto Stock Exchange (“Canadian Rules”). AQN is also subject to corporate governance requirements prescribed by the listing standards of the New York Stock Exchange (“NYSE”) Stock Market, and certain rules and regulations promulgated by the SEC under the Exchange Act (including those applicable rules and regulations mandated by the Sarbanes-Oxley Act of 2002). In particular, Section 303A.00 of the NYSE Listed Company Manual requires AQN to have an audit committee that meets the requirements of Rule 10A-3 of the Exchange Act, and Section 303A.011 of the NYSE Listed Company Manual requires AQN to disclose any significant ways in which its corporate governance practices differ from those followed by U.S. companies listed on the NYSE. A description of those differences follows.

Section 303A.01 of the NYSE Listed Company Manual requires that boards have a majority of independent directors and Section 303A.02 defines independence standards for directors. AQN’s board of directors is responsible for determining whether or not each director is independent. In making this determination, the board of directors has adopted the higher standard of “independence” that applies to each member of its audit committee pursuant to Canadian National Instrument 52-110 Audit Committees and Rule 10A-3 of the Exchange Act instead of the definition of independence set forth in the NYSE rules. In applying this Canadian standard, the board of directors considers all relationships of its directors, including business, family and other relationships. Through this process, AQN’s board of directors also determines whether each member of its audit committee is independent pursuant to Canadian National Instrument 52-110 Audit Committees and Rule 10A-3 of the Exchange Act.

Section 303A.04(a) of the NYSE Listed Company Manual requires that all members of the nominating/corporate governance committee be independent as defined in the NYSE rules. In making this determination, the board of directors has adopted the standard of “independence” applicable to members of its audit committee, described in the preceding paragraph, rather than the NYSE rules.

Section 303A.05(a) of the NYSE Listed Company Manual requires that all members of the compensation committee be independent as defined in the NYSE rules. In making this determination, the board of directors has adopted the standard of “independence” applicable to members of its audit committee, described above, rather than the NYSE rules.

Section 303A.07(b)(iii)(A) of the NYSE Listed Company Manual requires, among other things, that the written charter of the audit committee state that the audit committee at least annually, obtain and review a report by the independent auditor describing the firm’s internal quality-control procedures, any material issues raised by the most recent internal quality-control review, or peer review, of the firm, or by any inquiry or investigation by governmental or professional authorities, within the preceding five years, respecting one or more independent audits carried out by the firm, and any steps taken to deal with any such issues. The written charter of the audit committee complies with Canadian Rules, but does not explicitly state that these functions are part of the purpose of the audit committee, which is not required by Canadian Rules.

Section 303A.08 of the NYSE Listed Company Manual requires that shareholders of a listed company be given the opportunity to vote on all equity compensation plans and material revisions thereto. AQN complies with Canadian Rules, which generally require that shareholders approve equity compensation plans. However, the Canadian Rules are not identical to the NYSE Rules. For example, Canadian Rules require shareholder approval of equity compensation plans only when such plans involve the issuance or potential issuance of newly issued securities. In addition, equity compensation plans that do not provide for a fixed maximum number of securities to be issued must have a rolling maximum number of securities to be issued, based on a fixed percentage of the issuer’s outstanding securities and must also be approved by shareholders every three years. If a plan provides a procedure for its amendment, Canadian Rules require shareholder approval of amendments only where the amendment involves a reduction in the exercise price or purchase price, or an extension of the term of an award benefiting an insider, the removal or exceeding of the insider participation limit prescribed by the Canadian Rules, an increase to the maximum number of securities issuable, or is an amendment to the amending provision itself.

Section 303A.09 of the NYSE Listed Company Manual requires that listed companies adopt and disclose corporate governance guidelines that address certain topics, including director compensation guidelines. AQN has adopted its Board Mandate, which is the equivalent of corporate governance guidelines, in compliance with the Canadian Rules.

AQN’s corporate governance guidelines do not address director compensation, but AQN provides disclosure about the decision making process for non-employee director compensation in the annual management information circular and AQN has adopted equity ownership guidelines for non-employee directors.

Section 303A.10 of the NYSE Listed Company Manual requires that a listed company’s code of business conduct and ethics mandate that any waiver of the code for executive officers or directors may be made only by the board or a board committee and must be promptly disclosed to shareholders. AQN’s code of business conduct and ethics complies with Canadian Rules. Waivers must receive prior approval by the board and will be disclosed promptly in accordance with applicable securities laws and AQN’s disclosure policy.

Section 312 of the NYSE Listed Company Manual requires that a listed company obtain shareholder approval prior to the issuance of securities in connection with the establishment or amendment of certain equity compensation plans, issuances of securities to related parties, the issuance of 20% or greater of shares outstanding or voting power and issuances that will result in a change in control. AQN has elected to follow the Canadian Rules for shareholder approval of new issuances of its common shares instead of the NYSE shareholder approval rules. Under the Canadian Rules, shareholder approval is required for certain issuances of shares that (i) materially affect control of AQN or (ii) provide consideration to insiders in aggregate of 10% or greater of the market capitalization of the listed issuer and have not been negotiated at arm’s length. Shareholder approval is also required, pursuant to the Canadian Rules, in the case of private placements (x) for an aggregate number of listed securities issuable greater than 25% of the number of securities of the listed issuer which are outstanding, on a non-diluted basis, prior to the date of closing of the transaction if the price per security is less than the market price or (y) that during any six month period are to insiders for listed securities or options, rights or other entitlements to listed securities greater than 10% of the number of securities of the listed issuer which are outstanding, on a non-diluted basis, prior to the date of the closing of the first private placement to an insider during the six month period.

In addition to the foregoing, the Company may from time-to-time seek relief from the NYSE corporate governance requirements on specific transactions under the NYSE Listed Company Guide, in which case, the Company expects to make the disclosure of such transactions available on the Company’s website at www.algonquinpowerandutilities.com. Information contained on the Company’s website is not part of this annual report on Form 40-F.

UNDERTAKING

AQN undertakes to make available, in person or by telephone, representatives to respond to inquiries made by the SEC staff, and to furnish promptly, when requested to do so by the SEC staff, information relating to the securities in relation to which the obligation to file an annual report on Form 40-F arises or transactions in said securities.

CONSENT TO SERVICE OF PROCESS

AQN previously filed with the SEC a written irrevocable consent and power of attorney on Form F-X. Any change to the name or address of the agent for service of AQN shall be communicated promptly to the SEC by amendment to Form F-X referencing the file number of AQN.

SIGNATURES

Pursuant to the requirements of the Securities Exchange Act of 1934, as amended, the Registrant certifies that it meets all of the requirements for filing on Form 40-F and has duly caused this Amendment No.1 to the annual report to be signed on its behalf by the undersigned, thereto duly authorized.

ALGONQUIN POWER & UTILITIES CORP.

(Registrant)

Date: March 21, 2023

By: /s/ Darren Myers
Name: Darren Myers
Title: Chief Financial Officer

EXHIBIT INDEX


Exhibit Number						Exhibit Description
99.1						Annual Information Form of AQN for the year ended December 31, 2022.*
99.2						Audited Annual Financial Statements of AQN for the year ended December 31, 2022.*
99.3						Management’s Discussion & Analysis of AQN for the year ended December 31, 2022.
99.4						Consent Letter from Ernst & Young LLP.*
99.5						Certifications of Chief Executive Officer pursuant to Section 302 of the Sarbanes-Oxley Act of 2002.
99.6						Certifications of Chief Financial Officer pursuant to Section 302 of the Sarbanes-Oxley Act of 2002.
99.7						Certifications of Chief Executive Officer pursuant to Section 906 of the Sarbanes-Oxley Act of 2002.
99.8						Certifications of Chief Financial Officer pursuant to Section 906 of the Sarbanes-Oxley Act of 2002.
101						Inline Interactive Data File.*
104						Cover Page Interactive Data File.

*Previously filed.

ALGONQUIN POWER & UTILITIES CORP.

ANNUAL INFORMATION FORM
For the year ended December 31, 2022

March 17, 2023

All information contained in this AIF is presented as at December 31, 2022, unless otherwise specified. In this AIF, all dollar figures are in U.S. dollars, unless otherwise indicated.

Table of Contents


1. CORPORATE STRUCTURE			3
1.1 Name, Address and Incorporation			3
1.2 Intercorporate Relationships			3
2. GENERAL DEVELOPMENT OF THE BUSINESS			5
2.1 Three Year History			6
2.1.1 Fiscal 2020			6
2.1.2 Fiscal 2021			7
2.1.3 Fiscal 2022			8
3. DESCRIPTION OF THE BUSINESS			10
3.1 Regulated Services Group			10
3.1.1 Description of Operations			10
3.1.2 Specialized Skill and Knowledge			15
3.1.3 Competitive Conditions			16
3.1.4 Cycles and Seasonality			16
3.2 Renewable Energy Group			17
3.2.1 Description of Operations			17
3.2.2 Specialized Skill and Knowledge			20
3.2.3 Competitive Conditions			20
3.2.4 Cycles and Seasonality			20
3.3 Corporate Development Activities			21
3.3.1 Development of Regulated Services Group Assets			21
3.3.2 Development of Renewable Energy Group Assets			21
3.4 Principal Revenue Sources			22
3.5 Environmental Protection			22
3.6 Employees			23
3.7 Foreign Operations			23

TABLE OF CONTENTS
(continued)


3.8 Economic Dependence			23
3.9 Social and Environmental Policies and Commitment to Sustainability			23
3.10 Credit Ratings			24
4. ENTERPRISE RISK FACTORS			26
4.1 Risk Factors Relating to Operations			27
4.2 Risk Factors Relating to Financing and Financial Reporting			36
4.3 Risk Factors Relating to Regulatory Environment			40
4.4 Risk Factors Relating to Strategic Planning and Execution			43
5. DIVIDENDS			50
5.1 Common Shares			50
5.2 Preferred Shares			50
5.3 Dividend Reinvestment Plan			50
6. DESCRIPTION OF CAPITAL STRUCTURE			51
6.1 Common Shares			51
6.2 Preferred Shares			51
6.3 Subordinated Notes			53
6.4 Equity Units			54
6.5 Shareholders’ Rights Plan			54
7. MARKET FOR SECURITIES			55
7.1 Trading Price and Volume			55
7.1.1 Common Shares			55
7.1.2 Preferred Shares			55
7.1.3 Subordinated Notes			56
7.1.4 Equity Units			57
7.2 Prior Sales			57

TABLE OF CONTENTS
(continued)


7.3 Escrowed Securities and Securities Subject to Contractual Restrictions on Transfer			57
8. DIRECTORS AND OFFICERS			58
8.1 Name, Occupation and Security Holdings			58
8.2 Audit Committee			61
8.2.1 Audit Committee Charter			61
8.2.2 Relevant Education and Experience			62
8.2.3 Pre-Approval Policies and Procedures			62
8.3 Corporate Governance, Risk, and Human Resources and Compensation Committees			62
8.4 Cease Trade Orders, Bankruptcies, Penalties or Sanctions			62
8.5 Conflicts of Interest			63
9. LEGAL PROCEEDINGS AND REGULATORY ACTIONS			63
9.1 Legal Proceedings			63
9.2 Regulatory Actions			63
10. INTEREST OF MANAGEMENT AND OTHERS IN MATERIAL TRANSACTIONS			63
11. TRANSFER AGENTS AND REGISTRARS			63
12. MATERIAL CONTRACTS			64
13. EXPERTS			64
14. ADDITIONAL INFORMATION			64

SCHEDULE A - Mandate of the Audit Committee A -1

SCHEDULE B - Glossary of Terms B-1

-1-

Caution Concerning Forward-Looking Statements and Forward-Looking Information

This document may contain statements that constitute “forward-looking information” within the meaning of applicable securities laws in each of the provinces and territories of Canada and the respective policies, regulations and rules under such laws or “forward-looking statements” within the meaning of the U.S. Private Securities Litigation Reform Act of 1995 (collectively, “forward-looking information”). The words “aims”, “anticipates”, “believes”, “budget”, “could”, “estimates”, “expects”, “forecasts”, “intends”, “may”, “might”, “plans”, “projects”, “schedule”, “should”, “targets”, “will”, “would”, “seeks”, "strives” (and grammatical variations of such terms) and similar expressions are often intended to identify forward-looking information, although not all forward-looking information contains these identifying words. Specific forward-looking information in this document includes, but is not limited to, statements relating to: expected future investments and growth, results of operations, performance, business prospects and opportunities of the Corporation; expectations regarding earnings and cash flows; expectations regarding the use of proceeds from financings; expectations regarding credit ratings and the maintenance thereof; statements relating to renewable energy credits expected to be generated and sold; statements regarding the Corporation’s sustainability and environmental, social and governance goals, including its net-zero by 2050 target; expectations and plans with respect to current and planned projects; expectations with respect to revenues pursuant to Offtake Contracts; financing plans, including the Corporation’s expectation that it will not undertake any new common equity financing through the end of 2024; the expected generating capacity and completion of the Sandhill RNG project; asset sales, including AQN’s targeting of approximately $1 billion in asset sales; sources of funding, including adequacy and availability of credit facilities, cash flows from operations, capital markets financing, and asset recycling initiatives; anticipated customer benefits; ongoing and planned acquisitions, dispositions, projects, initiatives or other transactions, including expectations regarding timing, costs, financing, results, ownership structures, regulatory matters, in-service dates and completion dates; expectations regarding the Corporation’s corporate development activities and the results thereof, including the expected business mix between the Regulated Services Group and Renewable Energy Group; expectations regarding future capital investments and development pipeline; strategy and goals; expected demand for renewable sources of power; expected capacity of and energy sales from new energy projects and existing facilities; joint ventures; environmental liabilities; dividends to shareholders, including the sustainability thereof; the Reinvestment Plan; expectations regarding the anticipated closing of the Kentucky Power Transaction; expectations regarding financing of the Kentucky Power Transaction; expectations regarding the timing for the transfer or retirement (for rate-making purposes in Kentucky) of the Mitchell Plant; expectations regarding future "greening the fleet" initiatives, including with respect to Kentucky Power; the future impact on the Corporation of actual or proposed laws, regulations and rules; and the implementation of new technology systems and infrastructure, including the expected timing thereof. All forward-looking information is given pursuant to the “safe harbour” provisions of applicable securities legislation.

The forecasts and projections that make up the forward-looking information contained herein are based on certain factors or assumptions which include, but are not limited to: the receipt of applicable regulatory approvals and requested rate decisions; the absence of a material increase in the costs of compliance with environmental laws following the completion of the Kentucky Power Transaction; the absence of material adverse regulatory decisions being received and the expectation of regulatory stability; the absence of any material equipment breakdown or failure; availability of financing (including tax equity financing and self-monetization transactions for U.S. federal tax credits) on commercially reasonable terms and the stability of credit ratings of AQN and its subsidiaries; the absence of unexpected material liabilities or uninsured losses; the continued availability of commodity supplies and stability of commodity prices; the absence of interest rate increases or significant currency exchange rate fluctuations; the absence of significant operational, financial or supply chain disruptions or liability, including relating to import controls and tariffs; the continued ability to maintain systems and facilities to ensure their continued performance; the absence of a severe and prolonged downturn in general economic, credit, social or market conditions; the successful and timely development and construction of new projects; the closing of pending acquisitions substantially in accordance with the expected timing for such acquisitions; the absence of capital project or financing cost overruns; sufficient liquidity and capital resources; the continuation of long-term weather patterns and trends; the absence of significant counterparty defaults; the continued competitiveness of electricity pricing when compared with alternative sources of energy; the realization of the anticipated benefits of the Corporation’s acquisitions and joint ventures; the absence of a change in applicable laws, political conditions, public policies and directions by governments, materially negatively affecting the Corporation; the ability to obtain and maintain licenses and permits; maintenance of adequate insurance coverage; the absence of material fluctuations in market energy prices; the absence of material disputes with taxation authorities or changes to applicable tax laws; continued maintenance of information technology infrastructure and the absence of a material breach of cybersecurity; the successful implementation of new information technology systems and infrastructure; favourable relations with external stakeholders; favourable labour relations; the realization of the anticipated benefits of the Kentucky Power Transaction; that the Corporation will be able to successfully integrate newly acquired entities, and the absence of any material adverse changes to such entities prior to closing; the successful transfer of operational control over the Mitchell Plant to Wheeling Power Company; the Mitchell Plant being transferred or retired in accordance with the Corporation’s expectations; the absence of undisclosed liabilities of entities being acquired; that such entities will maintain constructive regulatory relationships with state regulatory authorities; the ability of the Corporation to retain key personnel of acquired entities and the value of such employees; no adverse developments in the business and affairs of the sellers during the period when transitional services are provided to the Corporation in connection with any acquisition; the ability of the Corporation to satisfy its liabilities and meet its debt service obligations following completion of any acquisition; the absence of any reputational harm to the Corporation as a result of any acquisition; and the ability of the Corporation to successfully execute future “greening the fleet” initiatives.

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The forward-looking information contained herein is subject to risks, uncertainties and other factors that could cause actual results to differ materially from historical results or results anticipated by the forward-looking information. Factors which could cause results or events to differ materially from current expectations include, but are not limited to: changes in general economic, credit, social or market conditions; changes in customer energy usage patterns and energy demand; reductions in the liquidity of energy markets; global climate change; the incurrence of environmental liabilities; natural disasters, diseases, pandemics, public health emergencies and other force majeure events; critical equipment breakdown or failure; supply chain disruptions; the imposition of import controls or tariffs; the failure of information technology infrastructure and other cybersecurity measures to protect against data, privacy and cybersecurity breaches; failure to successfully implement, and cost overruns and delays in connection with, new information technology systems and infrastructure; physical security breach; the loss of key personnel and/or labour disruptions; seasonal fluctuations and variability in weather conditions and natural resource availability; reductions in demand for electricity, water and natural gas due to developments in technology; reliance on transmission systems owned and operated by third parties; issues arising with respect to land use rights and access to the Corporation’s facilities; terrorist attacks; fluctuations in commodity and energy prices; capital expenditures; reliance on subsidiaries; the incurrence of an uninsured loss; a credit rating downgrade; an increase in financing costs or limits on access to credit and capital markets; significant inflation; increases and fluctuations in interest rates and failure to manage exposure to credit and financial instrument risk; currency exchange rate fluctuations; restricted financial flexibility due to covenants in existing credit agreements; an inability to refinance maturing debt on favourable terms; disputes with taxation authorities or changes to applicable tax laws; failure to identify, acquire, develop or timely place in service projects to maximize the value of tax credits; requirement for greater than expected contributions to post-employment benefit plans; default by a counterparty ; inaccurate assumptions, judgments and/or estimates with respect to asset retirement obligations; failure to maintain required regulatory authorizations; changes in, or failure to comply with, applicable laws and regulations; failure of compliance programs; failure to identify attractive acquisition or development candidates necessary to pursue the Corporation’s growth strategy; failure to dispose of assets (at all or at a competitive price) to fund the Corporation’s operations and growth plans; delays and cost overruns in the design and construction of projects, including as a result of COVID-19; loss of key customers; failure to complete or realize the anticipated benefits of acquisitions or joint ventures; Atlantica or a third party joint venture partner acting in a manner contrary to the Corporation’s interests; a drop in the market value of Atlantica’s ordinary shares; facilities being condemned or otherwise taken by governmental entities; increased external stakeholder activism adverse to the Corporation’s interests; fluctuations in the price and liquidity of the Common Shares and the Corporation’s other securities; the severity and duration of the COVID-19 pandemic, including the potential resurgence of COVID-19 and/or new strains of COVID-19 and collateral consequences thereof, including the disruption of economic activity, volatility in capital and credit markets and legislative and regulatory responses; impact of significant demands placed on the Corporation as a result of pending acquisitions or growth strategies; potential undisclosed liabilities of any entities being acquired by the Corporation; uncertainty regarding the length of time required to complete pending acquisitions; the failure to implement the Corporation’s strategic objectives or achieve expected benefits relating to acquisitions; Kentucky Power’s failure to receive regulatory approval for the construction of new renewable generation facilities; indebtedness of any entity being acquired by the Corporation; reputational harm and increased costs of compliance with environmental laws as a result of announced or completed acquisitions; unanticipated expenses and/or cash payments as a result of change of control and/or termination for convenience provisions in agreements to which any entity being acquired is a party; and the reliance on third parties for certain transitional services following the completion of an acquisition. Although the Corporation has attempted to identify important factors that could cause actual actions, events or results to differ materially from those described in forward-looking information, there may be other factors that cause actions, events or results not to be as anticipated, estimated or intended. Some of these and other factors are discussed in more detail under the heading “Enterprise Risk Factors” in this AIF and under the heading “Enterprise Risk Management” in the Corporation's management discussion and analysis for the three and twelve months ended December 31, 2022 (which may be found on SEDAR at www.sedar.com and on EDGAR at www.sec.gov/edgar) (“MD&A”).

Forward-looking information contained herein is provided for the purposes of assisting the reader in understanding the Corporation and its business, operations, risks, financial performance, financial position and cash flows as at and for the periods indicated and to present information about management's current expectations and plans relating to the future, and the reader is cautioned that such information may not be appropriate for other purposes. Forward-looking information contained herein is made as of the date of this document and based on the plans, beliefs, estimates, projections, expectations, opinions and assumptions of management on the date hereof. There can be no assurance that forward-looking information will prove to be accurate, as actual results and future events could differ materially from those anticipated in such forward-looking information. Accordingly, readers should not place undue reliance on forward-looking information. While subsequent events and developments may cause the Corporation’s views to change, the Corporation disclaims any obligation to update any forward-looking information or to explain any material difference between subsequent actual events and such forward-looking information, except to the extent required by applicable law. All forward-looking information contained herein is qualified by these cautionary statements.

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1.CORPORATE STRUCTURE

1.1Name, Address and Incorporation

Algonquin Power & Utilities Corp. (“AQN”) was originally incorporated under the Canada Business Corporations Act on August 1, 1988 as Traduction Militech Translation Inc. Pursuant to articles of amendment dated August 20, 1990 and January 24, 2007, the Corporation amended its articles to change its name to Société Hydrogenique Incorporée – Hydrogenics Corporation and Hydrogenics Corporation – Corporation Hydrogenique, respectively. Pursuant to a certificate and articles of arrangement dated October 27, 2009, the Corporation, among other things, created a new class of common shares, transferred its existing operations to a newly formed independent corporation, exchanged new common shares for all of the trust units of Algonquin Power Co. (“APCo”) and changed its name to Algonquin Power & Utilities Corp. AQN amended its articles on November 2, 2012, January 1, 2013, February 27, 2014, October 16, 2018, May 21, 2019 and January 14, 2022 to provide for the creation of series of preferred shares of the Corporation. See “Description of Capital Structure – Preferred Shares”. On June 10, 2016, the Corporation amended its articles to provide for a minimum of three directors and a maximum of 20 directors and to provide that the registered office of the Corporation be situated anywhere within the Province of Ontario. The head and registered office of AQN is located at Suite 100, 354 Davis Road, Oakville, Ontario L6J 2X1.

Unless the context indicates otherwise, references in this AIF to the “Corporation” refer collectively to AQN, its direct or indirect subsidiary entities and partnership interests held by AQN and its subsidiary entities.

1.2Intercorporate Relationships

Most of the Corporation’s business is conducted through subsidiary entities, including those entities which hold project assets. The following chart depicts, in summary form, the Corporation’s key businesses as of the date of this AIF.

The following table outlines the Corporation’s significant subsidiaries, and excludes certain other subsidiaries. The assets and revenues of the excluded subsidiaries did not individually exceed 10%, or in the aggregate exceed 20%, of the total consolidated assets or total consolidated revenues of the Corporation as at December 31, 2022. The voting securities of each subsidiary are held in the form of common shares, share quotas or partnership interests in the case of partnerships and their foreign equivalents, and units in the case of trusts.

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Significant Subsidiaries	Description	Jurisdiction	Ownership of Voting Securities
REGULATED SERVICES GROUP
Liberty Utilities (Canada) Corp.		Canada	100%
Liberty Utilities Co. (“Liberty Utilities”)		Delaware	100%
Liberty Utilities (CalPeco Electric) LLC	Owner of the CalPeco Electric System	California	100%
Liberty Utilities (Granite State Electric) Corp.	Owner of the Granite State Electric System	New Hampshire	100%
Liberty Utilities (EnergyNorth Natural Gas) Corp.	Owner of the EnergyNorth Gas System	New Hampshire	100%
Liberty Utilities (Litchfield Park Water & Sewer) Corp.	Owner of the Litchfield Park Water System	Arizona	100%
Liberty Utilities (Midstates Natural Gas) Corp.	Owner of the Midstates Gas Systems	Missouri	100%
Liberty Utilities (Peach State Natural Gas) Corp.	Owner of the Peach State Gas System	Georgia	100%
Liberty Utilities (New England Natural Gas Company) Corp.	Owner of the New England Gas System	Delaware	100%
Liberty Utilities (New York Water) Corp.	Owner of the New York Water System	New York	100%
Liberty Utilities (St. Lawrence Gas) Corp.	Owner of the St. Lawrence Gas System	New York	100%
The Empire District Electric Company (“Empire”)	Owner of, among other things, electric and electric transmission utility assets serving locations in Missouri, Kansas, Oklahoma and Arkansas, and power generation assets	Kansas	100%
Neosho Ridge Wind, LLC	Owner of the Neosho Ridge Wind Facility	Delaware	100%1
North Fork Ridge Wind, LLC	Owner of the North Fork Ridge Wind Facility	Delaware	100%1
Kings Point Wind, LLC	Owner of the Kings Point Wind Facility	Delaware	100%1
The Empire District Gas Company (“EDG”)	Operator of a natural gas distribution utility in Missouri	Kansas	100%
Liberty Utilities (Canada) LP (“Liberty Utilities Canada”)		Ontario	100%
Liberty Utilities (Gas New Brunswick) LP	Owner of the New Brunswick Gas System	New Brunswick	100%
Bermuda Electric Light Company Limited	Owner of an electric distribution, transmission and generation system in Bermuda	Bermuda	100%
Empresa de Servicios Sanitarios de Los Lagos S.A.	Owner of a water and wastewater system in Chile	Chile	64%
RENEWABLE ENERGY GROUP
Liberty (AY Holdings) B.V. (“AY Holdings”)	Owner of approximately 42% equity interest in Atlantica	Netherlands	100%
Algonquin Power Co.		Ontario	100%
Altavista Solar, LLC	Owner of the Altavista Solar Facility	Virginia	100%
Deerfield Wind Energy, LLC	Owner of the Deerfield Wind Facility	Delaware	51%2
GSG 6, LLC	Owner of the Shady Oaks Wind Facility	Illinois	100%
Maverick Creek Wind, LLC	Owner of the Maverick Creek Wind Facility	Delaware	100%1
Minonk Wind, LLC	Owner of the Minonk Wind Facility	Delaware	100%
Odell Wind Farm, LLC	Owner of the Odell Wind Facility	Minnesota	51%2
Senate Wind, LLC	Owner of the Senate Wind Facility	Delaware	100%
St. Leon Wind Energy LP (“St. Leon LP”)	Owner of the St. Leon Wind Facility	Manitoba	100%
Sugar Creek Wind One LLC	Owner of the Sugar Creek Wind Facility	Delaware	51%2

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1 The Corporation directly or indirectly holds 100% of the managing interests, with 100% of the non-managing interests directly or indirectly held by third-party partners.

2 Indicates the managing interest held by the Corporation, with the remaining 49% managing interest held by a third-party partner. 100% of the non-managing interests are directly or indirectly held by third-party partners.

2.GENERAL DEVELOPMENT OF THE BUSINESS

The Corporation owns and operates a diversified portfolio of regulated and non-regulated generation, distribution, and transmission assets. AQN seeks to maximize total shareholder value through new investments in renewable power generating facilities, regulated utilities and other complementary infrastructure projects, supported by the Corporation’s focus on operational excellence and sustainability. Through these activities, the Corporation aims to drive growth in earnings and cash flows to support a sustainable dividend and share price appreciation.

One of AQN’s financial objectives is to maintain a BBB flat investment grade credit rating. In an effort to realize that objective, AQN monitors and strives to adhere to various targets communicated by rating agencies related to their assessments of financial and business risk at AQN. These targets currently include expectations that AQN satisfies specific leverage targets and continues to generate at least 70% of EBITDA (as determined by applicable rating agency methodologies) from AQN’s Regulated Services Group. In pursuing its strategy, AQN evaluates investment opportunities with a view to preserving its ability to achieve these rating agency targets, which would require AQN to grow its Regulated Services Group at least in the same proportions as the Renewable Energy Group. The business mix target may from time to time require AQN to grow its Regulated Services Group or implement other strategies, such as asset recycling, in order to pursue investment opportunities within its Renewable Energy Group.

The Corporation’s operations are organized across two primary business units consisting of: the Regulated Services Group, which primarily owns and operates a portfolio of regulated assets in the United States, Canada, Bermuda and Chile; and the Renewable Energy Group, which owns and operates, or has investments in, a diversified portfolio of renewable generation assets. The Corporation also undertakes business development activities for both business units, primarily in North America, working to identify, develop, acquire, invest in, or divest of renewable energy facilities, regulated utilities and other complementary infrastructure projects. See “Description of the Business – Corporate Development Activities” for more information.


Regulated Services Group						Renewable Energy Group

Electric Utilities Water and Wastewater Utilities Natural Gas Utilities Electric and Natural Gas Transmission Energy Generation and Storage						Wind Power Generation Solar Generation Hydro Electric Generation Thermal Co-Generation Renewable Natural Gas Energy Storage

Regulated Services Group

The Regulated Services Group primarily operates a diversified portfolio of regulated utility systems located in the United States, Canada, Bermuda and Chile serving approximately 1,244,000 customer connections as of December 31, 2022. The Regulated Services Group seeks to provide safe, high quality and reliable services to its customers and to deliver stable and predictable earnings to the Corporation. In addition to encouraging and supporting organic growth within its service territories, the Regulated Services Group seeks to deliver long-term growth through accretive acquisitions of additional utility systems and pursuing “greening the fleet” opportunities.

Renewable Energy Group

The Renewable Energy Group generates and sells electrical energy produced by its diverse portfolio of renewable power generation and clean power generation facilities primarily located across the United States and Canada. The Renewable Energy Group seeks to deliver growth through new power generation projects and complementary projects, such as energy storage. The Renewable Energy Group operates, and directly owns interests in hydroelectric, wind, solar, RNG and thermal facilities with a combined gross generating capacity of approximately 2.5 GW and a net generating capacity (attributable to the Renewable Energy Group) of approximately 2.1 GW.

In addition to the assets that the Renewable Energy Group operates, the Renewable Energy Group has investments in generating assets with approximately 1.4 GW of net generating capacity, which includes the Corporation’s 51% interest in the Texas Coastal Wind Facilities and approximately 42% indirect beneficial interest in Atlantica Sustainable Infrastructure plc (formerly Atlantica Yield plc) (“Atlantica”), a NASDAQ-listed company that acquires, owns and manages a diversified international portfolio of contracted renewable energy, power generation, electric transmission and water assets. AQN reports its investment in Atlantica under the Renewable Energy Group.

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2.1Three Year History

The following is a description of the general development of the business of the Corporation over the last three fiscal years.

2.1.1Fiscal 2020

Corporate

(i)Management Changes

On February 5, 2020, AQN announced the appointment of Arun Banskota to the newly-created position of President. On July 17, 2020, AQN announced the retirement of Ian Robertson and the appointment of Mr. Banskota to the role of Chief Executive Officer. On September 18, 2020, AQN announced the retirement of David Bronicheski and the appointment of Arthur Kacprzak to the role of Chief Financial Officer. On October 9, 2020, AQN announced the retirement of Christopher Jarratt as Vice-Chair.

(ii)Corporate Credit Facilities

Given the uncertainty around the COVID-19 pandemic, on April 9, 2020, AQN entered into a new $865 million delayed draw non-revolving term credit facility with a syndicate of banks and a $135 million bilateral delayed draw non-revolving term facility. On October 5, 2020, these two delayed draw facilities were replaced with a $1 billion revolving credit facility with a syndicate of banks, which matured on December 31, 2021.

(iii)At-the-Market Equity Program

On May 15, 2020, AQN re-established its at-the-market equity program, which allowed AQN to issue up to $500 million (or the equivalent in Canadian dollars) of Common Shares from treasury to the public from time to time, at AQN's discretion, at the prevailing market price when issued on the TSX, the NYSE, or any other existing trading market for the Common Shares in Canada or the United States. The Corporation’s at-the-market equity program became inactive after having lapsed upon the filing of the Corporation’s current base shelf prospectus on November 18, 2021. On August 15, 2022, AQN re-established its at-the-market equity program.

See “Three Year History – Fiscal 2022 – Corporate – At-the-Market Equity Program” for additional information regarding AQN’s current at-the-market equity program.

(iv)July 2020 Offering of Common Shares

On July 17, 2020, AQN completed a public offering of approximately 57.5 million Common Shares, comprised of approximately 37 million Common Shares that were widely marketed and sold through a syndicate of underwriters (including the exercise of the over-allotment option), and a concurrent direct offering of approximately 20.5 million Common Shares that were sold to an institutional investor. The Common Shares were issued at a price of C$17.10 per Common Share for aggregate gross proceeds of approximately C$982.7 million.

Regulated Services Group

(i)Issuance of C$200 million of Senior Unsecured Debentures

On February 14, 2020, Liberty Utilities Canada issued C$200 million of senior unsecured debentures bearing interest at 3.315% and with a maturity date of February 14, 2050. The debentures were issued at par.

(ii)Regulated Services Group Credit Facilities

Given the uncertainty around the COVID-19 pandemic, on April 9, 2020, the Regulated Services Group entered into a $600 million delayed draw non-revolving term credit facility with a syndicate of banks. On October 5, 2020, this delayed draw facility was replaced with a $600 million revolving credit facility with a syndicate of banks, which matured on December 31, 2021.

(iii)Acquisition of ESSAL

On September 11, 2020, AQN entered into an agreement to acquire from Aguas Andinas S.A. its 53.5% direct and indirect participation in the water utility company Empresa de Servicios Sanitarios de Los Lagos S.A. (“ESSAL”) for approximately $92.3 million. In compliance with local regulations, a tender offer process was launched for the remaining shares of ESSAL. The tender offer was completed on October 14, 2020 and the settlement of the tendered shares occurred on October 19, 2020, resulting in AQN acquiring, in total, approximately 94% of the outstanding shares of ESSAL for an aggregate purchase price of approximately $162.1 million. On December 21, 2020, AQN entered into a share purchase agreement under which Toesca Infraestructura II Fondo de Inversión agreed to purchase an approximately 31.9% interest in Eco Acquisitionco SpA (the holding company through which AQN's interests in ESSAL are held) for a purchase price of approximately $51.8 million, which closed on January 4, 2021. As a result, AQN indirectly owns approximately 64% of the outstanding shares of ESSAL. ESSAL is a vertically integrated, regional water and wastewater provider with approximately 244,000 customer connections in Southern Chile.

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For more detail on ESSAL, see “Description of the Business – Regulated Services Group – Description of Operations – Water Distribution and Wastewater Collection Systems” below.

(iv)Issuance of $600 Million of Senior Unsecured Notes

On September 23, 2020, the Regulated Services Group, through its financing affiliate Liberty Utilities Finance GP1, completed an inaugural offering into the U.S. 144A market with the issuance of $600 million of “green” senior unsecured notes bearing interest at 2.050% and having a maturity date of September 15, 2030.

(v)Completion of the Acquisition of Liberty Group Limited

On November 9, 2020, AQN announced that it successfully completed its acquisition of Ascendant Group Limited (subsequently renamed Liberty Group Limited) for approximately $365 million. Liberty Group Limited, through its major subsidiary, Bermuda Electric Light Company Limited (“BELCO”), is the sole electric utility in Bermuda, providing regulated electrical transmission and distribution services to approximately 36,000 customer connections and the majority of the regulated bulk electrical generation on the island.

For more detail on BELCO, see “Description of the Business – Regulated Services Group – Description of Operations – Electric Distribution Systems” below.

Renewable Energy Group

(i)Renewable Energy Group Credit Facility

On February 24, 2020, the Renewable Energy Group increased availability under its revolving letter of credit facility to $350 million.

(ii)Renewable Energy Development Framework Agreement

On July 30, 2020, the Renewable Energy Group announced an agreement with Chevron seeking to co-develop renewable power projects that are expected to provide electricity to strategic Chevron assets. In connection with this agreement, four projects in the Permian Basin totalling 120 MW received a final investment decision to proceed from both partners in 2021.

(iii)Completion of Great Bay II Solar Facility and the Sugar Creek Wind Facility

On August 13, 2020, the 43 MW Great Bay II Solar Facility, located in Somerset County, Maryland achieved commercial operation. On November 9, 2020, the 202 MW Sugar Creek Wind Facility, located in Logan County, Illinois, achieved commercial operation.

(iv)Definitive Agreement to Acquire 51% Interest in a Portfolio of Texas Coastal Wind Facilities

On November 20, 2020, the Renewable Energy Group entered into an agreement to acquire a 51% interest in a portfolio of four wind facilities (Stella, Cranell, East Raymond and West Raymond) (collectively the “Texas Coastal Wind Facilities”) from RWE Renewables, a subsidiary of RWE AG. The Texas Coastal Wind Facilities, located in the coastal region of south Texas, have an aggregate capacity of 861 MW.

2.1.2Fiscal 2021

Corporate

(i)June 2021 Offering of Equity Units

On June 23, 2021, the Corporation closed an underwritten marketed public offering of 20,000,000 “green” equity units (the “Equity Units”) for total gross proceeds of $1.0 billion (the “Equity Unit Offering”). The underwriters subsequently exercised their option to purchase an additional 3,000,000 Equity Units on the same terms as the Equity Unit Offering, bringing the total gross proceeds including the over-allotment to $1.15 billion.

At issuance, each Equity Unit consisted of a 1/20 or 5% undivided beneficial interest in a $1,000 principal amount 1.18% remarketable senior note of the Corporation due June 15, 2026, and a contract to purchase Common Shares on June 15, 2024 based on a reference price determined by the volume-weighted average AQN common share price over the preceding 20 day trading period. Total annual distributions on the Equity Units are at the rate of 7.75%.

See “Description of Capital Structure – Equity Units” for additional details on the Equity Units.

(ii)Net-Zero Goal

On October 5, 2021, AQN announced its target to achieve net-zero (scope 1 and 2 greenhouse gas emissions) by 2050.

(iii)November 2021 Offering of Common Shares

On November 8, 2021, the Corporation completed a bought deal Common Share offering of 44,080,000 Common Shares, at a price of C$18.15 per share, for total gross proceeds of approximately C$800 million (the “2021 Bought Deal Offering”). AQN intends to use the net proceeds of the 2021 Bought Deal Offering to partially finance the Kentucky Power Transaction (as defined below); provided that, in the short-term, prior to the closing of the Kentucky Power Transaction, the Corporation has used such net proceeds to repay certain indebtedness of AQN and its subsidiaries.

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Regulated Services Group

(i)Agreement to Acquire Kentucky Power Company and AEP Kentucky Transmission Company

On October 26, 2021, the Regulated Services Group, through Liberty Utilities, entered into an agreement with American Electric Power Company, Inc. and AEP Transmission Company, LLC (collectively, the “Sellers”) to acquire Kentucky Power Company (“Kentucky Power”) and AEP Kentucky Transmission Company, Inc. (“Kentucky TransCo”) for a total purchase price of approximately $2.846 billion, including the assumption of approximately $1.221 billion in debt (the “Kentucky Power Transaction”). On September 29, 2022, the parties entered into an amendment to the Kentucky Acquisition Agreement that, among other things, reduces the purchase price by $200 million to approximately $2.646 billion, including the assumption of approximately $1.221 billion in debt. On January 16, 2023, the parties entered into a further amendment to the Kentucky Acquisition Agreement in order to clarify the parties’ understanding and agreement with respect to seeking approval for the Kentucky Power Transaction from FERC.

Kentucky Power is a state rate-regulated electricity generation, distribution and transmission utility serving 20 eastern Kentucky counties and operating under a cost of service framework. Kentucky TransCo is an electricity transmission business operating in the Kentucky portion of the transmission infrastructure that is part of PJM. Kentucky Power and Kentucky TransCo are both regulated by FERC. Closing of the Kentucky Power Transaction remains subject to the satisfaction or waiver of certain conditions precedent, which include the approval of the Kentucky Power Transaction by FERC and clearance under the Hart-Scott-Rodino Antitrust Improvements Act of 1976 (as the clearance received previously has lapsed). On December 15, 2022, FERC issued an order denying, without prejudice, authorization for the Kentucky Power Transaction. On February 14, 2023, a new application was filed with FERC for approval of the Kentucky Power Transaction. If the Kentucky Power Transaction has not closed by April 26, 2023, either party may, if certain requirements are met, terminate the Kentucky Acquisition Agreement in accordance with its terms.

(ii)Completion of Midwest Greening the Fleet Initiative

The Regulated Services Group successfully completed the construction and acquisition of all the wind facilities (North Fork Ridge, Kings Point and Neosho Ridge) related to its inaugural “greening the fleet” initiative. The initiative consists of 600 MWs of new strategically located wind energy generation which is expected to provide benefits to the Regulated Services Group's electric customers in Missouri, Arkansas, Oklahoma and Kansas.

On January 27, 2021, Empire closed its acquisition of the North Fork Ridge Wind Facility, and on May 5, 2021, Empire closed the acquisitions of the Kings Point and Neosho Ridge Wind Facilities.

Renewable Energy Group

(i)Issuance of C$400 Million of Senior Unsecured Debentures

On April 9, 2021, the Renewable Energy Group issued C$400 million of “green” senior unsecured debentures bearing interest at 2.85% and with a maturity date of July 15, 2031.The debentures were sold at a price of C$999.92 per C$1,000.00 principal amount.

(ii)Completion of the Maverick Creek Wind Facility, Altavista Solar Facility and Val-Éo Wind Facility

On April 21, 2021, the approximately 492 MW Maverick Creek Wind Facility, located in Concho County, Texas, achieved commercial operation. On June 1, 2021, the 80 MW Altavista Solar Facility, located in Campbell County, Virginia, achieved commercial operation. On December 31, 2021, the 24 MW Val-Éo wind facility, located in Lac-Saint-Jean-Est County, Québec, achieved commercial operation.

(iii)Acquisition of 51% Interest in a Portfolio of Texas Coastal Wind Facilities

In the first quarter of 2021, the Renewable Energy Group closed the acquisitions of a 51% interest in three of the four Texas Coastal Wind Facilities (Stella, Cranell and East Raymond) that it had previously agreed to purchase from RWE Renewables, a subsidiary of RWE AG. On August 12, 2021, the Renewable Energy Group closed the acquisition of a 51% interest in the West Raymond Wind Facility. The Texas Coastal Wind Facilities have a total generating capacity of 861 MW. The Texas Coastal Wind Facilities are located in the coastal region of south Texas and are expected to provide a complementary wind resource to the Corporation's existing assets in the State.

2.1.3Fiscal 2022

Corporate

(i)Offering of Subordinated Notes

On January 18, 2022, AQN completed an underwritten offering of (i) C$400 million aggregate principal amount of 5.25% fixed-to-fixed reset rate junior subordinated notes series 2022-A (the “2022-A Subordinated Notes”) due January 18, 2082 and (ii) $750 million aggregate principal amount of 4.75% fixed-to-fixed reset rate junior subordinated notes series 2022-B (the “2022-B Subordinated Notes”) due January 18, 2082 (collectively, the “2022 Subordinated Note Offerings”). Upon the occurrence of certain bankruptcy-related events in respect of AQN, the 2022-A Subordinated Notes automatically convert into preferred shares, Series H of AQN (the “Series H Shares”) and the 2022-B Subordinated Notes automatically convert into preferred shares, Series I of AQN (the “Series I Shares”). AQN intends to use the net proceeds of the 2022 Subordinated Note Offerings to partially finance the Kentucky Power Transaction, provided that, in the short-

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term, prior to the closing of the Kentucky Power Transaction, the Corporation has used such net proceeds to repay certain indebtedness of AQN and its subsidiaries.

See “Description of Capital Structure – Subordinated Notes” for more detail on the 2022-A Subordinated Notes and the 2022-B Subordinated Notes and see “Description of Capital Structure – Preferred Shares” for more detail on the Series H Shares and Series I Shares.

(ii)At-the-Market Equity Program

On August 15, 2022, AQN re-established its at-the-market equity program, which allows AQN to issue up to $500 million (or the equivalent in Canadian dollars) of Common Shares from treasury to the public from time to time, at AQN's discretion, at the prevailing market price when issued on the TSX, the NYSE or on any other existing trading market for the Common Shares in Canada or the United States. On January 12, 2023, AQN announced that no new common equity financings were expected through the end of 2024.

(iii)Management Changes

On August 30, 2022, AQN announced that Arthur Kacprzak was stepping down as Chief Financial Officer and announced the appointment of Darren Myers to such role.

Regulated Services Group

(i)Acquisition of Liberty New York Water (formerly New York American Water Corporation, Inc.)

Effective January 1, 2022, the Regulated Services Group closed the acquisition of New York American Water Company, Inc. (subsequently renamed Liberty Utilities (New York Water) Corp.) (“Liberty New York Water”) for a purchase price of approximately $609 million. Liberty New York Water is a regulated water and wastewater utility serving approximately 127,000 customer connections across eight counties in southeastern New York. Operations include approximately 1,270 miles of water mains and distribution lines with 98% of customers in Nassau County on Long Island. The purchase price for the acquisition of Liberty New York Water was funded through drawings on a $1.1 billion senior unsecured delayed draw non-revolving term credit facility of Liberty Utilities entered into on December 20, 2021.

For more detail on the New York Water System, see “Description of the Business – Regulated Services Group – Description of Operations – Water Distribution and Wastewater Collection Systems” below.

(ii)Regulated Services Group Credit Facilities

On April 29, 2022, the Regulated Services Group entered into a $1.0 billion senior unsecured revolving credit facility and a $500.0 million senior unsecured revolving credit facility.

Renewable Energy Group

(i)Completion of the Blue Hill Wind Facility

On April 14, 2022, the 175 MW Blue Hill Wind Facility, located in southwest Saskatchewan achieved commercial operation. AQN subsequently sold an 80% ownership in the Blue Hill Wind Facility as part of the 2022 Asset Recycling Transaction.

See “Three Year History – Fiscal 2022 – Renewable Energy Group – Completion of Inaugural Asset Recycling Transaction” for more detail on the 2022 Asset Recycling Transaction.

(ii)Renewable Energy Group Credit Facilities

On July 22, 2022, the Renewable Energy Group entered into a $250 million uncommitted bilateral letter of credit facility.

(iii)Completion of Sandhill Renewable Natural Gas Acquisition

On August 5, 2022, the Renewable Energy Group completed its acquisition of Sandhill Advanced Biofuels, LLC (“Sandhill”). Sandhill is a developer of RNG anaerobic digestion projects located on dairy farms with a portfolio of four projects in the state of Wisconsin. Two of the projects achieved commercial operation in August 2022, while the other two projects are expected to reach commercial operation in late 2023 and 2024, respectively. Once fully constructed, the portfolio is expected to produce RNG at a rate of approximately 500 million British thermal units per day. The acquisition represents the Corporation’s first investment in the non-regulated RNG space.

(iv)Completion of Inaugural Asset Recycling Transaction

On December 29, 2022, the Renewable Energy Group closed the previously announced sale of ownership interests in a portfolio of operating wind facilities in the United States and Canada to InfraRed Capital Partners, an international infrastructure investment manager that is part of SLC Management, the institutional alternatives and traditional asset management business of Sun Life Financial Inc. (the “2022 Asset Recycling Transaction”). The 2022 Asset Recycling Transaction consisted of the sale of (1) a 49% ownership interest in three operating wind facilities in the United States totalling 551 MW of installed capacity: the Odell Wind Facility in Minnesota, the Deerfield Wind Facility in Michigan, and the Sugar Creek Wind Facility in Illinois; and (2) an 80% ownership interest in the operating 175 MW Blue Hill Wind Facility in Saskatchewan. Total cash proceeds to AQN from the 2022 Asset Recycling Transaction were approximately $277.5 million for the U.S. facilities and approximately C$108.6 million for the Blue Hill Wind Facility (in each case subject

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to certain potential future post-closing adjustments). The Renewable Energy Group will continue to oversee day-to-day operations and provide management services to each of the facilities.

3.DESCRIPTION OF THE BUSINESS

3.1Regulated Services Group

The Regulated Services Group operates a diversified portfolio of rate-regulated utilities located in the United States, Canada, Chile and Bermuda that, as at December 31, 2022, provided distribution services to approximately 1,244,000 customer connections in the electric (approximately 309,000 customer connections), water and wastewater (approximately 560,000 customer connections) and natural gas sectors (approximately 375,000 customer connections). See “Principal Revenue Sources” for a breakdown of revenue by regulated service type.

The Regulated Services Group’s electrical distribution utility systems and related transmission and generation assets are located in the states of Arkansas, California, Kansas, Missouri, New Hampshire, and Oklahoma, and in Bermuda. The Regulated Services Group’s water distribution and wastewater collection utility systems are located in the states of Arizona, Arkansas, California, Illinois, Missouri, New York and Texas, and in Chile. The Regulated Services Group’s natural gas distribution utility systems are located in the province of New Brunswick and the states of Georgia, Illinois, Iowa, Massachusetts, Missouri, New Hampshire and New York. The Regulated Services Group also owns and operates generating assets with a gross capacity of approximately 2.0 GW and has investments in generating assets with approximately 0.3 GW of net generation capacity. Below is a breakdown of revenue for the Regulated Services Group by geographic area for the twelve months ended December 31, 2022.


Geographic Area			% of Total Revenue
United States			83%
Canada			3%
Bermuda			10%
Chile			4%

3.1.1Description of Operations

Electric Distribution Systems

(i)Method of Providing Services and Distribution Methods

Electric distribution is the final stage in the delivery system of providing electricity to end users. An electric distribution utility sources and distributes electricity to its customers through a network of buried or overhead lines. The electricity is sourced from power generation facilities. The electricity is transported from the source(s) of generation at high voltages through transmission lines and is then reduced through transformers to lower voltages at substations. The electricity from the substations is then delivered through distribution lines to the customers where the voltage is again lowered through a transformer for use by the customer.

The rates charged for electric distribution service are comprised of a fixed charge that recovers customer related costs, such as meter readings, and a variable rate component that recovers the cost of generation, transmission and distribution. Other revenues are comprised of fees for other services such as establishing a connection, late fee, reconnections, and energy efficiency programs.

The electric utilities located in Arkansas, California, Kansas, Missouri, New Hampshire and Oklahoma are subject to state regulation and rates charged by these utilities must be reviewed and approved by their respective state regulatory authorities. Similarly, the electric utility in Bermuda, BELCO, is subject to regulation by the RAB and its rates must be approved by the RAB.

(ii)Principal Markets and Regulatory Environments

The Regulated Services Group operates electrical distribution systems in the states of Arkansas, California, Kansas, Missouri, New Hampshire and Oklahoma, and in Bermuda under a cost-of-service methodology. The utilities use either an historical test year, adjusted pro-forma for known and measurable changes, in the establishment of their rates, or prospective test years based on expenses expected to be incurred in future periods. Pursuant to these methods, the revenue requirement upon which rates are based is determined by applying an approved return on rate base, and adding depreciation, operating expenses and administrative and general expenses.

Rate cases allow for a particular utility the opportunity to recover its appropriate operating costs and earn a reasonable rate of return on its capital investment as allowed by the regulatory authority under which the utility operates.

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(iii)Selected Facilities

(1)CalPeco Electric System

The CalPeco Electric System provides electric distribution service to the Lake Tahoe basin and surrounding areas. The service territory, centered on a highly popular tourist destination, has a customer base spread throughout Alpine, El Dorado, Mono, Nevada, Placer, Plumas and Sierra counties in northeastern California. CalPeco Electric System’s connection base is primarily residential. Its commercial connections consist primarily of ski resorts, hotels, hospitals, schools and grocery stores. The CalPeco Electric system is regulated by the CPUC.

The Corporation entered into a new multi-year services agreement with NV Energy that commenced in December 2020 and expires in December 2025. The services agreement obligates NV Energy to use commercially reasonable efforts to supply the CalPeco Electric System with sufficient renewable power to, when combined with the output of the CalPeco Electric System’s Luning Solar Facility and Turquoise Solar Facility, satisfy the current California Renewables Portfolio Standard requirement for the term of the services agreement. This agreement lowers fixed rates for customers, while providing the opportunity to add renewable generation capacity. The CalPeco Electric System received approval from CPUC to recover the costs it will incur under this agreement. The CalPeco Electric System has authorization for rate recovery of the costs that the CalPeco Electric System has or will incur to acquire, own and operate the Luning Solar Facility and the Turquoise Solar Facility.

(2)Granite State Electric System

The Granite State Electric System provides distribution service in southern and northwestern New Hampshire, centered around operating centres in Salem in the south and Lebanon in the northwest. The Granite State Electric System’s customer base includes a mixture of residential, commercial and industrial customers. The Granite State Electric System consists of approximately 900 circuit miles, 40 distribution circuits and 12 electric distribution substations.

The Granite State Electric System is regulated by the NHPUC and FERC. The Granite State Electric System is required to provide electric commodity supply for all customers who do not choose to take supply from a competitive supplier (“Energy Service”) in the New England power market and is allowed to fully recover its costs for the provision and administration of Energy Service under the Energy Service Adjustment Factor, as approved by the NHPUC. The Granite State Electric System must file with the NHPUC twice a year to adjust for market prices of power purchased.

(3)Empire District Electric System

Based in Joplin, Missouri, Empire is a regulated utility providing electric and natural gas in parts of Missouri, Kansas, Oklahoma and Arkansas. The largest urban area served is the city of Joplin, Missouri, and its immediate vicinity. The vertically-integrated regulated electricity operations of Empire represent around half of the Regulated Services Group’s operating revenues and assets. Empire’s customer base includes a mixture of residential, commercial, and industrial customers. Empire also operates a fibre optics business.

Empire is subject to regulation by the MPSC, the KCC, the OCC, the APSC and FERC.

Empire has various owned generation located in Missouri and Kansas, all of which operate in the SPP. Its facilities include, among others, the approximately 150 MW North Fork Ridge Wind Facility located in northwestern Jasper County and southwestern Barton County, Missouri; the approximately 150 MW Kings Point Wind Facility located in Barton County, southwestern Dade County, northeastern Jasper County, and northwestern Lawrence County, Missouri; the approximately 460 MW State Line thermal generation plant, located in Joplin, Missouri; the approximately 288 MW Energy Center, a thermal generation plant located in Sarcoxie, Missouri; the approximately 300 MW Neosho Ridge Wind Facility located in Neosho County, Kansas and the approximately 320 MW Riverton thermal generation plant located in Riverton, Kansas.

(4)BELCO Electric System

BELCO is the sole provider of electricity transmission, distribution, and retail services to all customers in Bermuda and is a bulk generator of electricity on the island. BELCO’s customer base includes a mixture of residential, commercial, and industrial customers. Its network includes approximately 1,000 km of high voltage distribution lines, approximately 600 km of low voltage overhead service lines, approximately 200 km of underground transmission cables and 34 substations.

BELCO is regulated by the RAB, the sole utility regulator in Bermuda. The Electricity Act 2016 brought changes to Bermuda’s electricity market which included the development of the first integrated resource plan, the encouragement of competitive electricity generation and a new retail tariff methodology.

Water Distribution and Wastewater Collection Systems

(i)Method of Providing Services and Distribution Methods

A water and/or wastewater utility services company provides utility water supply and/or wastewater collection and treatment services to its customers.

A water utility sources, treats and stores potable water and subsequently distributes it to its customers through a network of buried pipes (distribution mains). The raw water for human consumption is sourced from the ground and extracted through wells or from surface water such as lakes or rivers. The water is treated to potable water standards that are specified in federal and state regulations as administered and which are typically enforced by a federal, state or

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local agency. Following treatment, the water is either pumped directly into the distribution system or pumped into storage reservoirs from which it is subsequently pumped into the distribution system. This system of wells, pumps, storage vessels and distribution infrastructure is owned and maintained by the private utility. The fees or rates charged for water are comprised of a fixed charge component plus a variable fee based on the volume of water used. Additional fees are typically charged for other services such as establishing a connection, late fees and reconnects.

A wastewater utility collects wastewater from its customers and transports it through a network of collection pipes, lift stations and manholes to a centralized facility where it is treated, rendering it suitable for discharge to the environment or for reuse, usually as irrigation. The wastewater is ultimately delivered to a treatment plant. Primary treatment at the plant consists of the screening out of larger solids, floating material and other foreign objects and, at some facilities, grit removal. These removed materials are hauled to a landfill. Secondary treatment at the plant consists of biological digestion of the organic and other impurities which is performed by beneficial bacteria in an oxygen enriched environment. Excess and spent bacteria are collected from the bottom of the tanks, digested and/or dewatered, and the resulting solids are sent to landfill or to land application as a soil amendment. The treated water, referred to as “effluent”, is then used for irrigation or groundwater recharging or is discharged by permit into adjacent surface water. The standards to which this wastewater is treated are specified in each treatment facility’s operating permit and the wastewater is routinely tested to ensure its continuing compliance therewith. The effluent quality standards are based on federal and state regulations which are administered, and continuing compliance is enforced by the state agency to which federal enforcement powers are delegated.

(ii)Principal Markets and Regulatory Environments

The Regulated Services Group’s water and wastewater facilities are located in the United States in the states of Arizona, Arkansas, California, Illinois, Missouri, New York and Texas, and in Chile. The water and wastewater utilities are generally subject to regulation by the public utility commissions of the jurisdiction in which they operate. The respective public utility commissions have jurisdiction with respect to rate, service, accounting procedures, issuance of securities, acquisitions and other matters. These utilities generally operate under cost-of-service regulation as administered by these regulatory authorities. The utilities generally use a historic or forward-looking test year in the establishment of rates for the utility and pursuant to this method the determination of the rate of return on approved rate base, recovery of depreciation on plant, together with all reasonable and prudent operating costs, establishes the revenue requirement upon which each utility’s customer rates are determined.

Rate cases allow a particular utility the opportunity to recover appropriate operating costs and to earn a rate of return on its capital investment as allowed by the regulatory authority under which the facility operates. The Corporation monitors the rates of return on each of its water and wastewater utility investments to determine the appropriate time to file rate cases in order to ensure it earns the regulatory approved rate of return on its investments. Rates are approved by the agency to provide the utility the opportunity, but not the guarantee, to earn a reasonable return on its investment after recovering its prudently incurred operating expenses.

(iii)Selected Facilities

(1)Litchfield Park Water System

The Litchfield Park Water System is a regulated water and wastewater utility located in and around the cities of Avondale, Goodyear and Litchfield Park west of Phoenix, Arizona that has a service area that includes the City of Litchfield Park and sections of the cities of Goodyear and Avondale as well as portions of unincorporated Maricopa County. Litchfield Park Water System’s operations consist of thirteen well sites, two reservoir sites, and approximately 500 km of water mains and distribution lines. Wastewater operations at the Litchfield Park Water System consists of two lift stations, approximately 400 km of collection mains to the Palm Valley Water Reclamation Facility with a permitted treatment capacity of 6.55 million gallons per day. The Litchfield Park Water System’s customer base includes a mixture of residential, commercial, and industrial customers. The Litchfield Park Water System is regulated by the Arizona Corporate Commission.

(2)Liberty Park Water and Liberty Apple Valley Water System

Liberty Utilities (Park Water) Corp. (“Liberty Park Water”) provides, owns and operates the water system in central Los Angeles. Liberty Park Water also wholly owns Liberty Utilities (Apple Valley Ranchos Water) Corp. (“Liberty Apple Valley Water”), which is a regulated utility providing water utility services to customers in and around the Town of Apple Valley, California. Liberty Park Water’s and Liberty Apple Valley Water’s customer base includes a mixture of residential, commercial, and industrial customers. The Liberty Park Water system consists of approximately 400 km of pipeline, 10 wells, 8 booster pump stations, and 6.9 million gallons of storage reservoirs and tank capacity. The Liberty Apple Valley Water system consists of approximately 800 km of pipeline, 21 wells, 8 booster pump stations, and 12 million gallons of storage reservoirs and tank capacity. Liberty Park Water and Liberty Apple Valley Water are regulated by the CPUC and use a forward-looking, multi-year rate plan.

(3)ESSAL System

ESSAL is a vertically integrated water and wastewater utility company in Southern Chile. The utility operates 51 potable water production systems, 29 sewage plants, approximately 2,270 km of drinking water distribution networks and approximately 1,980 km of sewage networks covering 31 municipalities in the provinces of Valdivia, Ranco, Osorno, Llanquihue, Chiloé and Palena in the regions of Los Lagos and Los Ríos. The Corporation indirectly owns approximately

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64% of the outstanding shares of ESSAL. ESSAL’s customer base includes a mixture of residential, commercial, and industrial customers. ESSAL is regulated by the Superintendence of Sanitary Services of Chile.

(4)New York Water System

The New York Water System is a regulated water and wastewater utility serving customers across eight counties in southeastern New York. Operations include approximately 1,270 miles of water mains and distribution lines, 92 groundwater wells, 52 treatment stations and 41 tanks. Approximately 86% of the New York Water System’s customer base is residential, with 98% of customers located in Nassau County on Long Island.

The New York Water System is regulated by the New York Public Service Commission. The New York Water System has a reconciliation mechanism designed to allow the Corporation to recover or refund, through a surcharge or credit, the annual difference between projections of revenues, production costs, and property taxes and the actual amounts experienced by the New York Water System. The New York Water System also utilizes an infrastructure surcharge mechanism to recover water quality and system improvement investments, and a pension and other post-employment benefits tracker mechanism that tracks changes from authorized expenses.

Natural Gas Distribution Systems

(i)Method of Providing Services and Distribution Methods

Natural gas is a fossil fuel composed almost entirely of methane (a hydrocarbon gas) usually found in deep underground reservoirs formed by porous rock. In making its journey from the wellhead to the customer, natural gas may travel thousands of miles through interstate pipelines owned and operated by pipeline companies. Along the route, the natural gas may be stored underground in depleted oil and gas wells or other natural geological formations for use during seasonal periods of high demand. Interstate pipelines interconnect with other pipelines and other utility systems and offer system operators flexibility in moving the natural gas from point to point. The interstate pipeline companies are regulated by FERC. Typically, the distribution network operates pipelines (including transmission and distribution pipelines), gate stations, district regulator stations, peak shaving plants and natural gas meters. The natural gas distribution utilities owned by the Regulated Services Group are subject to state or provincial regulation and rates charged by these facilities may be reviewed and altered by the state or provincial regulatory authorities from time to time.

(ii)Principal Markets and Regulatory Environments

The Regulated Services Group owns and operates natural gas distribution systems, under cost-of-service regulation in the states of Georgia, Illinois, Iowa, Massachusetts, Missouri, New Hampshire and New York and the province of New Brunswick. In establishing rates, the natural gas utilities use either a historical test year that is adjusted on a pro-forma basis for known and measurable changes or a prospective test year based on expenses expected to be incurred in a future period, which is the methodology utilized in New Brunswick and Illinois. Pursuant to the prospective test year method, the revenue requirement upon which rates are based is determined by applying an approved return on rate base, and adding depreciation, operating expenses, and administrative and general expenses.

Rate cases allow a particular utility the opportunity to recover its appropriate operating costs and earn a reasonable rate of return on its capital investment as allowed by the regulatory authority under which the facility operates. The Corporation monitors the rates of return on its utility investments to determine the appropriate times to file rate cases, with the goal of earning a reasonable rate of return on its investments.

(iii)Selected Facilities

(1)EnergyNorth Gas System

The EnergyNorth Gas System is a regulated natural gas utility providing natural gas distribution services in 31 communities covering five counties in New Hampshire. Its franchise service area includes the communities of Nashua, Manchester, Concord, Keene, and Berlin. The EnergyNorth Gas System’s customer base includes a mixture of residential, commercial, industrial and transportation customers. The EnergyNorth Gas System operates and maintains approximately 2,370 km of underground distribution mains, approximately 71,100 service lines, and approximately 73 local and district regulator stations.

The EnergyNorth Gas System is regulated by the NHPUC. The EnergyNorth Gas System has a revenue per customer decoupling mechanism to recover lost distribution revenue associated with energy efficiency and to otherwise account for the effects of abnormal weather and economic conditions, and includes a real-time weather normalization adjustment. In addition, the EnergyNorth Gas System has a cost of gas adjustment mechanism that allows for monthly adjustments to account for commodity cost changes.

(2)Empire District Gas System

EDG is engaged in the distribution of natural gas in Missouri serving customers in northwest, north central and west central Missouri. EDG’s customer base includes a mixture of residential, commercial, industrial and transportation customers.

EDG is regulated by the MPSC. A PGA allows EDG to recover from its customers, subject to audit and final determination by regulators, the cost of purchased natural gas supplies and related carrying costs associated with EDG’s use of natural

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gas financial instruments to hedge the purchase price of natural gas. This PGA allows EDG to make rate changes periodically (up to four times) throughout the year in response to weather conditions and supply demands.

(3)Peach State Gas System

The Peach State Gas System is a regulated natural gas system providing natural gas distribution services in 13 communities covering six counties in Georgia. The Peach State Gas System franchise service area includes the communities of Columbus, Gainesville, Waverly Hall, Oakwood, Hamilton and Manchester. The Peach State Gas System’s customer base primarily includes a mixture of residential, commercial, industrial, and transportation customers. In addition, the Peach State Gas System has a 50-year privatization agreement to operate and maintain the natural gas system at Fort Benning.

The Peach State Gas System is regulated by the Georgia Public Service Commission. The Peach State Gas System’s rates are reviewed and updated annually through a tariff provision called the Georgia Rate Adjustment Mechanism. Georgia allows recovery of natural gas costs (including commodity price, transportation, reservation and demand costs, hedging costs, storage costs).

(4)New England Gas System

The New England Gas System is a regulated natural gas utility providing natural gas distribution services in nine communities, including Fall River, North Attleborough, Blackstone and surrounding communities, located in the southeastern portion of Massachusetts through approximately 1,000 km of gas distribution pipeline. The New England Gas System’s customer base includes a mixture of residential, commercial, and industrial customers.

The New England Gas System is regulated by the MDPU. The cost of natural gas is recoverable from customers through the Gas Adjustment Factor (“GAF”) when billed to “firm” natural gas customers included in approved tariffs by the MDPU. The GAF is adjusted twice annually and more frequently under certain circumstances.

(5)Midstates Gas Systems

The Midstates Gas Systems own regulated natural gas utilities providing natural gas distribution services to approximately 203 communities in the states of Illinois, Iowa and Missouri. The franchise service area includes the communities of Virden, Vandalia, Harrisburg and Metropolis in Illinois, Keokuk in Iowa, and Butler, Kirksville, Canton, Hannibal, Jackson, Sikeston, Malden and Caruthersville in Missouri. The Midstates Gas Systems’ customer base includes a mixture of residential, commercial, industrial and transportation customers.

The Midstates Gas Systems are regulated by the Illinois Commerce Commission, the Iowa Utilities Board and the MPSC. The regulators in Illinois, Iowa and Missouri allow recovery of natural gas costs (including commodity price, transportation, reservation and demand costs, hedging costs, and storage costs). The rate is adjusted monthly in Illinois and Iowa with an annual reconciliation. In Missouri, the rate is adjusted annually with allowance to file quarterly. In Missouri and Illinois, mechanisms exist to allow for the recovery of the revenue requirement approved by the regulator. In Missouri, the weather normalization adjustment mechanism allows for the adjustment in revenue due to weather and in Illinois, the volume balancing adjustment mechanism allows for the recovery of revenue due to variances in the volume of natural gas used.

(6)New Brunswick Gas System

The New Brunswick Gas System is regulated by the NB Energy Board and has a distribution network that includes approximately 1,200 kilometers of natural gas pipeline, and provides service to customers in 14 communities in New Brunswick. The NB Energy Board’s regulatory activities in the natural gas sector are primarily in relation to the New Brunswick Gas System which is the exclusive holder of the natural gas distribution franchise for the Province of New Brunswick, which expires in 2044 and is extendable for an additional 25-year period. The New Brunswick Gas System’s customer base includes a mixture of residential, commercial, and industrial customers.

For rate cases, the NB Energy Board can review all facets of the operations but primarily focuses on the approval of the previous calendar year’s regulatory financial statements, future test year budgets, establishing revenue requirements, rate design and other decisions like community expansion plans, customer retention and incentive programs, load retention rate proposals, return on equity, debt structure and rate class reviews.

(7)St. Lawrence Gas System

The St. Lawrence Gas System is a regulated natural gas utility operating approximatively 1,100 km of natural gas distribution pipeline. It distributes natural gas to customers in more than 20 communities in northern New York State, including the Villages of Canton, Malone, Massena, Potsdam and Ogdensburg located in St. Lawrence County, Franklin County and a portion of Lewis County. The St. Lawrence Gas System’s customer base includes a mixture of residential, commercial, industrial, and electric generation customers.

The St. Lawrence Gas System is regulated by the New York State Public Service Commission. In a traditional rate case filing, the filing includes historical operating results (test year) and a 12-month forecast for the period the rates will be in effect (rate year). More commonly, the St. Lawrence Gas System will endeavor to settle the rate case filing, in which case it is expected that there would be a multi-year plan in which the rate base and revenue requirement is adjusted for subsequent years within the plan. The St. Lawrence Gas System has a revenue decoupling mechanism which applies to residential and commercial customers within sales and transportation service types. This mechanism reconciles actual

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delivery service revenue to allowed delivery service revenues, which effectively adjusts the revenue for weather, energy efficiency, and customer numbers.

Electric and Natural Gas Transmission

(i)Method of Providing Services and Transmission Methods

Electric transmission is the bulk transportation of generated electricity over long distances from a generating site, such as a power plant, to an electrical substation. Transmission lines move large amounts of power at a high voltage level to a substation for voltage step-down and on to a lower voltage distribution network resulting in electricity delivered to homes and businesses. Transmission services obtained through FERC-governed OATT include network and point-to-point transmission service along with other ancillary services. Some examples of these types of services would be spinning and non-spinning reserves, black-start capability, regulation and voltage support and system control and dispatch.

Pipelines offer a variety of services under their FERC tariffs to include firm and interruptible transportation, along with other services to provide commercial markets additional flexibility. Some examples of these types of services would be park and loan, pooling and balancing services. In addition, firm service tariff features would also provide additional features to support secondary market activity to include, but not limited to capacity assignment, capacity releases, segmentation and renewal options.

(ii)Principal Markets and Regulatory Environments

Empire’s transmission rates and services and electric wholesale sales of electric energy in interstate commerce and its facilities are subject to the jurisdiction of FERC, under the Federal Power Act. Wholesale rate recovery of transmission costs, as with wholesale rate recovery of any other cost, is subject to FERC review.

The operations and rates of AQN’s transmission facility in New Brunswick are regulated by the NB Energy Board. It is entitled to recover the transmission revenue requirement, pursuant to the transmission tariff administered by New Brunswick Power Corporation. Any increase to its revenue requirement would result in an increase to the transmission rates under the OATT.

BELCO’s transmission rates are regulated by the RAB. BELCO’s transmission function and bulk generation functions are regulated under two licences held by BELCO: one for electricity transmission, distribution, and retail services and one for bulk generation.

Interstate natural gas pipeline transmission assets are regulated primarily by FERC under the Natural Gas Act. Under this framework, this agency authorizes and certifies all construction, and or abandonment of interstate natural gas pipeline facilities, requires certificate holders, once operational, to establish and maintain an OATT and publicly post capacity available for transportation, and the agency periodically reviews, under just and reasonable standards, the tariff rates to be charged by the certificate holder. In addition, FERC prescribes operating and safety standards to be followed along with other federal agencies such as Department of Transportation and the Occupational Safety and Health Administration.

(iii)Selected Facilities

(1)Empire Transmission Facilities

The Empire electric transmission facilities are located within a four state area of Missouri, Kansas, Oklahoma and Arkansas and primarily consist of approximately 22 miles of 345 kV lines, approximately 405 miles of 161 kV lines, approximately 750 miles of 69 kV lines and approximately 82 miles of 34.5 kV lines.

Empire is a member of the SPP which spans an area from the Canadian border in Montana and North Dakota in the north to parts of New Mexico, Texas and Louisiana in the south. The transmission facilities are offered for service under an OATT approved by FERC and administered by SPP. Service requests are placed in the SPP Open Access Same-Time Information System (OASIS) and is evaluated by SPP for available capacity. SPP determines who is offered available transmission capacity subject to the SPP Tariff and SPP Market Rules and is offered on a non-discriminatory basis. Service requests can be either point-to-point or network service, where network service is used for serving electric load. Empire is subject to four different states’ regulatory bodies, the Midwest Reliability Organization regional entity for NERC compliance, SPP Market Rules, and FERC.

3.1.2Specialized Skill and Knowledge

The Regulated Services Group requires specialized knowledge of its utility systems, including electrical, water and wastewater and natural gas. Upon acquiring a new utility system, the Regulated Services Group will typically retain the existing employees with such specialized skill and knowledge. In addition, the Regulated Services Group will add, when required, additional trained utility personnel at its corporate offices to support the expanded portfolio of utility assets. The Regulated Services Group has developed in-house regulatory expertise in order to interact with the state regulators in the various jurisdictions in which it operates. The Regulated Services Group believes that the relationship with regulators is unique to each state and therefore is best delivered by local managers who work in the service territory. The local regulatory teams meet with regulatory agencies on a regular basis to review regulatory policies, service delivery strategies, operating results and rate making initiatives.

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3.1.3Competitive Conditions

Generally, the Regulated Services Group’s utility businesses have geographic monopolies in their service territories. Competition at the Regulated Services Group’s electric distribution systems is primarily from other energy sources and on-site generation. Competition at the Regulated Services Group’s natural gas distribution systems is primarily with other methods of heating, including electricity, oil, and propane. Government policy and any changing societal perceptions of natural gas could also impact the competitiveness of natural gas in relation to other energy sources.

3.1.4Cycles and Seasonality

(i)Electricity Systems

The CalPeco Electric System’s demand for energy sales fluctuate depending on weather conditions. The CalPeco Electric System is a winter-peaking utility. Above normal snowfall in the Lake Tahoe area may bring more tourists and may increase demand for electricity. The CalPeco Electric System has implemented a BRRBA rate mechanism that removes the annual variations of recorded revenues to ensure that it recovers its authorized base revenues (gross revenues less fuel, purchased power, and other non-base revenues) over each rate case cycle.

The Granite State Electric System experiences peak loads in both the winter and summer seasons, due to heating and cooling loads associated with New England weather. The competitive market for power supply is managed by the ISO-NE. Generally, the Energy Service price for power may fluctuate as a result of the weather, but those costs are typically passed through directly to customers.

The Empire District Electric System experiences peak loads in both the winter and summer seasons, due to heating and cooling loads associated with weather in its service territory. Generally, the Energy Service price for power may fluctuate as a result of the weather, but those costs are typically passed through directly to customers, but certain unusual or extraordinary events may require different forms of cost recovery.

BELCO system’s demand is largely driven by peak loads in a six-month period of hot, humid weather followed by six months of relatively mild weather. Demand is driven by cooling requirements with a very small amount of heating required.

(ii)Water and Wastewater Systems

Demand for water is affected by weather conditions including temperature and precipitation. For certain service areas, water usage during the summer months is significantly greater than the winter months primarily because of the outdoor water usage associated with irrigation as well as the water used for other purposes including swimming pools and cooling systems.

When either the amount or frequency of precipitation is significantly above average, water usage may decrease, resulting in reduced operating revenues. Drought conditions arise when the amount and frequency of precipitation is significantly below average for an extended period of time. Drought conditions may lead to voluntary and mandatory restrictions on water usage and thereby impact the Corporation’s ability to recover its fixed costs in delivering clean, safe, and reliable water to customers at reasonable rates.

The Regulated Services Group attempts to mitigate the risk of reduced water usage by seeking regulatory mechanisms in rate case proceedings. Certain regulatory jurisdictions have approved regulatory mechanisms that address changes in the actual recorded water usage as compared to the authorized water usage. For example, for the Liberty Park Water system, the water revenue adjustment mechanism tracks the difference between the CPUC authorized commodity revenue and the actual recorded commodity revenue to ensure recovery of fixed costs that are recovered through the commodity or quantity charge. The purpose of the mechanism is to de-couple water usage from revenues. Not all regulatory jurisdictions in which the Regulated Services Group operates have approved mechanisms to mitigate reduced water usage and the resulting reduction in revenues.

(iii)Natural Gas Systems

The Regulated Services Group’s primary demand for natural gas from its natural gas distribution systems is driven by the seasonal heating requirements of its residential, commercial and industrial customers. The colder the weather, the greater the demand for natural gas to heat homes and businesses. As such, the natural gas distribution systems’ demand profile typically peaks in the winter months of January and February and declines in the summer months of July and August. Year to year variability also occurs depending on how cold the weather is in any particular year.

The Regulated Services Group attempts to mitigate the above noted fluctuations by seeking regulatory mechanisms during rate case proceedings. Certain jurisdictions have approved constructs to mitigate demand fluctuations. For example, at the Peach State Gas System, EnergyNorth Gas System and Midstates Gas Systems, a weather normalization adjustment is applied to customer bills that adjusts commodity rates to stabilize the revenues of the utility for changes in billing units attributable to weather patterns. Most regulatory jurisdictions in which the Regulated Services Group operates have approved mechanisms to mitigate natural gas demand fluctuations.

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3.2Renewable Energy Group

The Renewable Energy Group generates and sells electrical energy, capacity, ancillary products and renewable attributes produced by its diverse portfolio of renewable and clean power generation facilities primarily located throughout the United States and Canada. The Renewable Energy Group seeks to deliver growth through new power generation projects and other complementary projects, such as RNG and energy storage.

The Renewable Energy Group operates, and directly owns interests in hydroelectric, wind, solar, RNG and thermal facilities with a combined gross generating capacity of approximately 2.5 GW and a net generating capacity (attributable to the Renewable Energy Group) of approximately 2.1 GW. Approximately 81% of the electrical output is sold pursuant to long-term contractual arrangements which as of December 31, 2022 had a production-weighted average remaining contract life of approximately 11 years. In addition to the assets that the Renewable Energy Group operates, the Renewable Energy Group has investments in generating assets with approximately 1.4 GW of net generating capacity, which includes the Corporation’s 51% interest in the Texas Coastal Wind Facilities and approximately 42% indirect beneficial interest in Atlantica. Atlantica owns and operates a portfolio of international clean energy and water infrastructure assets under long term contracts with a Cash Available for Distribution (CAFD) weighted average remaining contract life of approximately 14 years as of December 31, 2022.

Below is a breakdown of the Renewable Energy Group's generating capacity by geographic area as of December 31, 2022, which is comprised of net generating capacity of facilities owned and operated, as well as net generating capacity of investments (including the Corporation’s 51% interest in the Texas Coastal Wind Facilities and approximately 42% interest in Atlantica).


Geographic Area			% of Generating Capacity
United States			75%
Canada			11%
International			14%

3.2.1Description of Operations

Wind Power Generating Facilities

(i)Production Method

The energy of the wind can be harnessed for the production of electricity through the use of wind turbines. A wind energy system transforms the kinetic energy of wind into electrical energy that can be delivered to the electricity distribution system for use by energy consumers. When the wind blows, large rotor blades on the wind turbines are rotated, generating energy that is converted to electricity. Most modern wind turbines consist of a rotor mounted on a shaft connected to a speed increasing gear box and high-speed generator. Monitoring systems control the angle of and power output from the rotor blades to ensure that the rotor blades are turned to face the wind direction, and generally to monitor the wind turbines installed at a facility.

There are 16 completed wind power generating facilities that the Renewable Energy Group both operates and owns interests in. These 16 wind facilities have a combined gross generating capacity of approximately 2.0 GW and a net generating capacity (attributable to the Renewable Energy Group) of approximately 1.6 GW. The Renewable Energy Group also owns a 51% equity interest in, but does not operate, the Texas Coastal Wind Facilities, a group of four wind facilities with a gross installed capacity of 861 MW, representing a net installed capacity to the Renewable Energy Group of 439 MW.

(ii)Principal Markets and Distribution Methods

The principal markets for the Renewable Energy Group’s completed wind facilities in Canada are Manitoba, Ontario, Saskatchewan and Québec. The electricity generated by the wind turbines is connected to the local transmission system and purchased by Manitoba Hydro, the IESO, SaskPower and Hydro-Québec, in the respective provinces. The principal markets for the Renewable Energy Group’s completed wind facilities in the United States are PJM, MISO and ERCOT.

(iii)Selected Canadian Facilities

(1)St. Leon Wind Facility

The St. Leon Wind Facility is an approximately 120 MW (including phase 1 and phase 2) wind powered electrical generating facility located near St. Leon, Manitoba, approximately 150 km southwest of Winnipeg. The St. Leon Wind Facility entered into a long-term PPA with Manitoba Hydro under which all electricity produced is sold to Manitoba Hydro.

(2)Amherst Island Wind Facility

The Amherst Island Wind Facility is an approximately 74 MW wind powered electric generating facility located on Amherst Island near the village of Stella, approximately 15 km southwest of Kingston. The Renewable Energy Group's interest in the project was previously held in a joint venture with the EPC contractor. In May 2019 the Corporation

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entered into a partnership, in which the Corporation holds a 98.5% interest and Atlantica holds a 1.5% interest, in respect of the Amherst Island Wind Facility. The electricity generated by the project is being sold under a long-term PPA awarded as part of the IESO FIT program.

(3)Blue Hill Wind Facility

The Renewable Energy Group owns a 20% interest in, and operates, the Blue Hill Wind Facility, a 175 MW wind powered electrical generating facility located in southwest Saskatchewan, approximately 200 km west of Regina, Saskatchewan. The output from the Blue Hill Wind Facility is being sold through a long-term power purchase agreement with an investment grade entity.

(iv)Selected United States Facilities

(1)Shady Oaks Wind Facility

The Shady Oaks Wind Facility is a 109.5 MW wind powered electrical generating facility located in Lee County, Illinois, approximately 80 km west of Chicago. The Shady Oaks Wind Facility is party to a long-term power sales contract with the largest electric utility in the state of Illinois, Commonwealth Edison. The power sales contract is structured to hedge the preponderance of the Shady Oaks Wind Facility’s production volume against exposure to PJM ComEd Hub current spot market rates. Annual production is subject to contingent curtailment based on certain regulatory constraints of the electricity purchaser. Ancillary services, including capacity, reactive power and RECs, are sold into the PJM market.

(2)Sandy Ridge Wind Facility

The Sandy Ridge Wind Facility is a 50 MW wind powered electrical generating facility located in Centre County, Pennsylvania, 180 km east of Pittsburgh. Sandy Ridge Wind, LLC is party to an energy production hedge (a “Primary Energy Production Hedge”) with respect to most of its production, which expires in 2030. In addition, under a long-term agreement with an energy services retailer, the Sandy Ridge Wind Facility will sell energy and RECs on a generator firm basis. Ancillary services, including capacity, reactive power and RECs, are sold into the PJM market.

(3)Minonk Wind Facility

The Minonk Wind Facility is a 200 MW wind powered electrical generating facility located near Minonk, IL, approximately 200 km southwest of Chicago, Illinois. The Minonk Wind Facility is party to a Primary Energy Production Hedge with an energy trading company. Ancillary services, including capacity, reactive power and RECs, are sold into the PJM market.

(4)Senate Wind Facility

The Senate Wind Facility is a 150 MW wind powered electrical generating facility located near Graham, Texas, approximately 200 km west of Dallas, Texas. The Senate Wind Facility is party to a long-term Primary Energy Production Hedge with an energy trading company. RECs are sold into the ERCOT market.

(5)Maverick Creek Wind Facility

The Maverick Creek Wind Facility is an approximately 492 MW wind powered electric generating facility located in Concho County, Texas, approximately 250 km northwest of Austin, Texas. The majority of the output of the Maverick Creek Wind Facility is being sold through two long-term PPAs with investment-grade entities.

(6)Odell Wind Facility

The Renewable Energy Group owns a 51% interest in, and operates, the Odell Wind Facility, a 200 MW wind powered electrical generating facility located near Windom, Minnesota, approximately 230 km southwest of Minneapolis, Minnesota. The Odell Wind Facility is party to a long-term PPA with an investment grade utility under which all electricity and RECs produced at the facility are sold.

(7)Deerfield Wind Facility

The Renewable Energy Group owns a 51% interest in, and operates, the Deerfield Wind Facility, a 149 MW wind powered electrical generating facility located in central Michigan, approximately 180 km north of Detroit, Michigan. All energy, capacity, and RECs produced at the facility are sold to a local electric distribution utility pursuant to a long-term PPA.

(8)Sugar Creek Wind Facility

The Renewable Energy Group owns a 51% interest in, and operates, the Sugar Creek Wind Facility, a 202 MW wind powered electric generating facility located in Logan County, Illinois, approximately 275 km southwest of Chicago, Illinois. The majority of the output of the Sugar Creek Wind Facility is being sold through a long-term financial hedge. All RECs from the facility are sold under long-term contracts to utilities in the state. Ancillary services, primarily capacity, are sold into the MISO market.

(9)Texas Coastal Wind Facilities

The Renewable Energy Group owns a 51% interest in, but does not operate, a portfolio of four wind facilities operated by RWE Renewables, a subsidiary of RWE AG, located in the coastal region of south Texas. The four wind facilities (Stella,

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Cranell, East Raymond and West Raymond) that make up the Texas Coastal Wind Facilities represent 861 MW of installed capacity. The four wind facilities have a weighted average offtake duration of approximately 10 years.

Solar Power Generating Facilities

(i)Production Method

Solar power is the conversion of sunlight into electricity, either directly using photovoltaics or indirectly using concentrated solar power. The Corporation’s solar generation facilities utilize photovoltaics which convert light into electric current using the photovoltaic effect. The array of a photovoltaic power system produces direct current power which fluctuates with the sunlight’s intensity. For practical use, commercial installations convert this direct current generated power to alternating current through the use of inverters. The Renewable Energy Group owns and operates six completed utility-scale solar power generating facilities and two community solar power generating facilities with a combined gross generating capacity of approximately 242 MW.

(ii)Principal Markets and Distribution Methods

The principal markets for the Renewable Energy Group’s completed solar facilities are Ontario, California and PJM. The electricity generated by the solar panels is transmitted via electrical collection lines to the facility substation for subsequent delivery to the distribution/transmission system under control of the local distribution company and the ISO.

(iii)Selected Facilities

(1)Bakersfield I Solar Facility

The Bakersfield I Solar Facility is a 20 MW solar powered electric generating facility located near Bakersfield, California, 150 km northwest of Los Angeles, California. The Bakersfield I Solar Facility has a long-term fixed rate PPA with an investor-owned utility.

(2)Great Bay I Solar Facility

The Great Bay I Solar Facility is a 75 MW solar powered electric generating facility located in Somerset County in southern Maryland, approximately 15 km south of Salisbury, Maryland. All energy from the Great Bay I Solar Facility is sold to the U.S. Government Services Administration pursuant to a long-term PPA. All RECs from the project are retained by the project company and sold into the Maryland market.

(3)Great Bay II Solar Facility

The Great Bay II Solar Facility is a 43 MW solar powered electric generating facility located in Somerset County in southern Maryland, approximately 15 km south of Salisbury, Maryland. The majority of the output of the Great Bay II Solar Facility is sold through a long-term financial hedge. All RECs from the project are sold into the Maryland market.

(4)Altavista Solar Facility

The Altavista Solar Facility is an 80 MW solar powered electric generating facility located in Campbell County, Virginia, approximately 185 km west of Richmond, Virginia. The majority of the output of the Altavista Solar Facility is being sold to a wholly-owned subsidiary of Meta, pursuant to a long-term PPA.

Hydroelectric Generating Facilities

(i)Production Method

A hydroelectric generating facility consists of a number of key components, including a dam, intake structure, electromechanical equipment consisting of a turbine(s) and a generator(s). A dam structure is required to create or increase the natural elevation difference between the upstream reservoir and the downstream tailrace, as well as to provide sufficient depth within the reservoir for an intake. Water flows are conveyed from the upstream reservoir to the generating equipment via a penstock or headrace canal and an intake structure. Turbine(s) and generator(s) transform the hydraulic energy into electrical energy. The water which has flowed through the hydraulic turbine(s) is discharged back to the natural watercourse. A transmission line is often required to interconnect a facility with the grid. The majority of hydroelectric generating facilities are also equipped with remote monitoring equipment, which allows the facility to be monitored and operated from a remote location. The Renewable Energy Group owns and operates 14 hydroelectric power generating facilities with a combined gross generating capacity of approximately 115 MW.

(ii)Principal Markets and Distribution Methods

The principal markets in which the Renewable Energy Group operates hydroelectric generating facilities in Canada are Alberta, Ontario, New Brunswick and Québec. In the U.S., the principal market is Maine. The majority of generated hydroelectricity is conveyed from the relevant facility to the purchasers under the terms of long-term PPAs. The electricity is generally transferred by transmission line from the generating facility to the delivery point for the purchaser, and it is distributed through the grid to end user customers of the purchaser.

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(iii)Selected Facility

(1)Tinker Hydro Facility

The Tinker Hydro Facility is located approximately 8 km north of Perth-Andover, New Brunswick and is situated near the mouth of the Aroostook River. The facility has a total nameplate capacity of approximately 33 MW.

As part of the generation assets in New Brunswick, the Corporation owns an electrical transmission system used to interconnect the Tinker Hydro Facility to the New Brunswick transmission network, provide transmission service to Perth Andover Electric Light Commission, and provide export/import capacity between Maine and New Brunswick.

The output of the Tinker Hydro Facility is actively marketed together with any applicable environmental attributes less any associated transportation costs. Additional energy and applicable environmental attributes are purchased from the market to supplement the energy generated from the Tinker Hydro Facility in order to service customer demand.

Thermal (Cogeneration) Electric Generating Facilities

(i)Production Method

Cogeneration is the simultaneous production of electricity and thermal energy such as hot water or steam from a single fuel source. The steam produced is normally required by an associated or nearby commercial facility, while the electricity generated is sold to a utility or used within the facility. Cogeneration provides facilities with greater efficiency, greater reliability and increased process flexibility than conventional generation methods. The Renewable Energy Group owns and operates two thermal electric power generating facilities with a combined gross generating capacity of approximately 127 MW.

(ii)Principal Markets and Distribution Methods

The principal markets for the Corporation’s cogeneration facilities are California and Connecticut. The electricity produced from these facilities is conveyed from the relevant facility to the electricity markets either under the terms of long-term contracts or according to ISO rules. In addition to grid sales of electricity and power, electricity and thermal energy are also sold to onsite or adjacent third-party thermal host facilities for use in production.

(iii)Selected Facilities

(1)Sanger Thermal Facility

The Sanger thermal cogeneration facility is a 56 MW natural gas-fired generating facility located in Sanger, California. The facility enters into resource adequacy offtake agreements on an annual basis (for one year terms) and is contracted through 2023.

(2)Windsor Locks Thermal Facility

The Windsor Locks thermal cogeneration facility (the “Windsor Locks Thermal Facility”) is a 71 MW natural gas-fired generating facility located in Windsor Locks, Connecticut. The Windsor Locks Thermal Facility supplies thermal steam energy and a portion of electrical generation to Ahlstrom Corporation pursuant to a ground lease and an energy services agreement. Payments under the energy services agreement are fully indexed to the cost of natural gas consumed by the Windsor Locks Thermal Facility. The additional installed capacity at the site is sold into the ISO-NE capacity market and energy is sold in the day ahead energy market as required under the ISO-NE capacity market rules.

3.2.2Specialized Skill and Knowledge

The Renewable Energy Group’s employees have extensive experience in the independent power industry. The production of energy from all facilities requires specialized skill and knowledge in relation to such facilities, their component parts and the various markets in which the projects are operated. The Renewable Energy Group uses a mix of self-performance and contractor-provided services in connection with the operation and maintenance of its facilities.

3.2.3Competitive Conditions

Deregulation has increased the demand for privately generated power from a variety of sources. With favourable government policy, the increased prevalence and commitment to carbon-reduction targets, evolving technology, deregulation and opening of competition in the electricity marketplace, the Corporation expects that there will continue to be both an increased opportunity and increased competition, as energy customers have increased choice among various forms of electricity generation and new entrants in the renewable energy industry continue to emerge.

3.2.4Cycles and Seasonality

(i)Wind Power Generating Facilities

The Renewable Energy Group’s wind generation facilities are impacted by seasonal fluctuations and year to year variability of the wind resource. During the fall, winter and spring periods, winds are generally stronger than during the summer period. The ability of these facilities to generate income may be impacted by naturally occurring changes in wind patterns and wind strength.

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(ii)Solar Power Generating Facilities

The Renewable Energy Group’s solar generation facilities are impacted by seasonal fluctuations and year to year variability in solar radiance. For instance, there are more daylight hours in the summer than there are in the winter, resulting in higher production in the summer months. The ability of these facilities to generate income may be impacted by naturally occurring changes in solar radiance, such as cloud cover and snow.

(iii)Hydroelectric Generating Facilities

The Renewable Energy Group’s hydroelectric operations are impacted by seasonal fluctuations and year to year variability of the available hydrology. These assets are primarily “run-of-river” and as such fluctuate with natural water flows. During the winter and summer periods, flows are generally lower, while during the spring and fall periods flows are generally higher. The ability of these assets to generate income may be impacted by changes in water availability or other material hydrologic events within a watercourse. Year to year, the level of hydrology varies, impacting the amount of power that can be generated in a year.

The Renewable Energy Group attempts to mitigate the above noted natural resource fluctuation risks by acquiring or developing generating stations in different geographic locations.

3.3Corporate Development Activities

The Corporation undertakes business development activities, primarily in North America, working to identify, develop, acquire, invest in, construct or divest of renewable energy facilities and other complementary infrastructure projects, and to invest in, or divest of, electric, water distribution and wastewater collection and natural gas utility systems.

3.3.1Development of Regulated Services Group Assets

The Regulated Services Group’s strategy is to grow its business organically and through earnings-accretive acquisitions. Anticipated capital expenditure initiatives for the Regulated Services Group include organic rate base capital investments, the pending Kentucky Power Transaction and initiatives focused on the transition to green energy.

3.3.2Development of Renewable Energy Group Assets

The Renewable Energy Group seeks to deliver growth through new power generation projects and other complementary projects, such as RNG and energy storage. The Renewable Energy Group is committed to working proactively with stakeholders, including local communities. The Renewable Energy Group believes that future opportunities for power generation and other related projects will continue to develop as new targets are set for renewable and other clean power generation projects. The Renewable Energy Group also has a pipeline of prospective greenfield projects that remain at an early stage of development.

The following table represents the Renewable Energy Group’s construction projects as of the date of this AIF:


Project Name	Location	Anticipated Size (MW)

Projects in Construction
Carvers Creek Solar Project1	Virginia	150
Community Solar Projects	New York	13
Deerfield II Wind Project1	Michigan	112
Hayhurst New Mexico Solar Project2	New Mexico	20
Hayhurst Texas Solar Project2	Texas	25
New Market Solar Project1	Ohio	100
Shady Oaks II Wind Project1	Illinois	108
Sandy Ridge II Wind Project1	Pennsylvania	88
Total Projects in Construction		616

1The project is currently held in a construction joint venture, of which the Renewable Energy Group and a third party each own a 50% equity

interest.

2The project is currently held in a joint venture, of which the Renewable Energy Group and an affiliate of Chevron each own a 50% equity

interest.

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3.4Principal Revenue Sources

AQN owns, directly or indirectly, interests in renewable generation facilities, thermal generation facilities, electricity distribution utilities, natural gas and propane distribution utilities, and water distribution and wastewater utilities.

The following provides a breakdown of the Corporation’s total revenue by percentage for the years ended December 31, 2021 and December 31, 2022:


	% of Total Revenue
	December 31, 2021	December 31, 2022
Utility electricity sales & distribution	52.0%	46.2%
Utility water distribution and wastewater treatment sales & distribution	10.3%	13.2%
Utility natural gas sales & distribution	23.1%	24.8%
Non-regulated energy sales	11.3%	12.7%
Other revenue1	3.2%	3.1%

1Other revenue includes natural gas transportation and RECs.

For the Regulated Services Group, the following provides a breakdown of revenue by percentage for the years ended December 31, 2021 and December 31, 2022:


	% of Revenue
	December 31, 2021	December 31, 2022
Utility electricity sales & distribution	59.2%	53.6%
Utility water distribution and wastewater treatment sales & distribution	11.8%	15.3%
Utility natural gas sales & distribution	26.3%	28.8%
Other revenue1	2.7%	2.3%

1Other revenue includes natural gas transportation.

For the Renewable Energy Group, the following provides a breakdown of revenue by percentage for the years ended December 31, 2021 and December 31, 2022:


	% of Revenue
	December 31, 2021	December 31, 2022
Wind generation	56.9%	58.4%
Solar generation	9.8%	7.9%
Hydroelectric generation	13.4%	13.6%
Thermal generation	13.3%	12.6%
Other revenue1	6.7%	7.5%

1Other revenue includes RECs.

3.5Environmental Protection

The Corporation is subject to federal, state, provincial and local laws, rules and regulations regarding water quality, hazardous and solid waste management, air quality control and other environmental matters. These laws, rules and regulations require the Corporation to conduct its operations in a specified manner and to obtain and comply with a wide variety of environmental registrations, licenses, permits, inspections and other approvals. Failure to comply with environmental laws, rules and regulations may expose the Corporation to significant fines, penalties and/or interruptions in operations. The Corporation’s environmental policies and procedures are intended to achieve compliance with such applicable laws and regulations, with environmental and compliance departments having responsibility for monitoring AQN and its subsidiaries’ operations. The Corporation engages in a process of updating and revising its procedures for the ongoing evaluation of its operations to identify potential environmental exposures and enhance compliance with regulatory requirements.

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Environmental protection requirements did not have a significant financial or operational effect on the Corporation’s capital expenditures, earnings and competitive position for the twelve months ended December 31, 2022. Moreover, other regimes that provide incentives and credits for generation of renewable energy and for carbon offsets, such as those described elsewhere in this AIF, are expected to increase the earnings and benefit the competitive position of the Corporation.

The Corporation faces a number of environmental risks that are normal aspects of operating within the renewable power generation, thermal power generation and utilities business segments which have the potential to become environmental liabilities (see “Enterprise Risk Factors – Risk Factors Relating to Operations”).

3.6Employees

The Corporation’s executive management group consists of 9 individuals. As at December 31, 2022, the Corporation employed a total of 3,951 people.

3.7Foreign Operations

For the twelve months ended December 31, 2022, 82.22% of the revenue of the Regulated Services Group and 71.56% of the revenue of the Renewable Energy Group was generated from operations located in the United States.

3.8Economic Dependence

The Corporation does not believe it is substantially dependent on any single contractual agreement or set of related agreements.

3.9Social and Environmental Policies and Commitment to Sustainability

The Corporation is committed to advancing a sustainable energy and water future. Sustainability is often defined by a company’s philosophy to operate in an economically, socially and environmentally sustainable manner, while recognizing the interests of its stakeholders. The Corporation believes this philosophy will contribute to a sustainable future for its investors, employees, customers, communities, business partners, governments and the environment. The Corporation has formal policies and procedures that support its commitment to sustainability.

Oversight of Sustainability

The mandate of the Board states that in providing oversight of the corporate strategy, the Board will review strategic plans in light of management’s assessment of emerging trends, opportunities, the competitive environment, risk issues and significant business practices. The Board has delegated to its Corporate Governance Committee primary oversight of sustainability matters, including the ongoing development of the Corporation’s sustainability plan and progress on sustainability initiatives. The Corporate Governance Committee reports to the Board on sustainability plans and initiatives.

Accountability for developing and managing the Corporation’s sustainability plans and initiatives has been assigned to AQN’s Executive Vice President, Strategy and Sustainability who leads the Corporation’s sustainability team. The mandate of the sustainability team is to ensure that the opportunities and risks relating to sustainability (environmental, social, and governance) as identified by the Corporation are considered and addressed as core components of the strategy and business processes of the organization, and to implement practices and programs that support the achievement of its mission.

In September 2018, the Corporation adopted its first Corporate Sustainability Policy. The Sustainability Policy is aligned with the United Nations’ Sustainable Development Goals (SDGs), namely Gender Equality (SDG5), Clean Water and Sanitation (SDG6), Affordable and Clean Energy (SDG7), Decent Work and Economic Growth (SDG8), Sustainable Cities and Communities (SDG11) and Climate Action (SDG13). In 2021, the Corporation further aligned with the UN SDGs by including these four additional SDGs: Industry, Innovation and Infrastructure (SDG9), Reduced Inequalities (SDG10), Responsible Consumption and Production (SDG12), and Life on Land (SDG15).

Social Policies

The Corporation’s Code of Business Conduct and Ethics is a key component of the Corporation’s sustainability plan. All directors, officers, employees, agents and contractors are expected to apply the Code of Business Conduct and Ethics to their work. The Corporation has also published a Human Rights Policy, which highlights its commitment to continue to act with integrity and respect for human rights.

The Corporation’s sustainability efforts incorporate local spending, local hiring and operational efficiency. The Corporation’s commitment to people is demonstrated through its employee training, learning and development programs, organizational improvements, emergency management programs and community involvement. Policies in place that support the Corporation’s commitment to sustainability include its Board and Executive Diversity Policy, Diversity Equity and Inclusion in the Workplace Policy, Ethics Reporting Policy, Supplier Code of Conduct and Human Rights Policy.

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Environmental, Health and Safety

The Corporation’s businesses have safety and environmental compliance policies in place. These policies have been communicated with employees and have been incorporated into their respective Safety Mission Statements and employee manuals. The Corporation’s Environmental and Health and Safety Groups are responsible for developing environmental and safety policies, developing and facilitating environmental and safety training, conducting internal audits of environmental and safety performance, and arranging for any third party environmental and safety audits. The Corporation is in the process of implementing an environmental management system designed to provide for the measurement, evaluation and improvement of the Corporation’s management of its environmental compliance, risks and performance. In addition, the Corporation has environmental programs in place that promote energy efficiency and responsible water usage, help facilitate habitat conservation to minimize impact, monitor greenhouse gas emissions and promote waste reduction and spill prevention.

ESG Report and Climate Change Assessment Report

On November 7, 2022, the Corporation released its 2022 ESG Report, which sets out the Corporation’s sustainability strategies, initiatives, goals and performance. The 2022 ESG Report outlines the Corporation’s progress towards its environmental, social and governance goals and demonstrates its ongoing commitment to delivering mission-critical services and renewable energy solutions. The 2022 ESG Report was prepared in accordance with the Global Reporting Initiative standards, and the Corporation has further enhanced its alignment to the United Nations’ Sustainable Development Goals, with the introduction of new goals and sub-targets that the Corporation feels align best with its business and strategy. The Corporation has also announced its target of achieving net-zero greenhouse gas emissions across its business operations for scope 1 and scope 2 emissions by 2050. In 2020, the Corporation formally began alignment with the Task Force on Climate-Related Financial Disclosures (“TCFD”) recommendations, and in December 2020, released its inaugural Climate Change Assessment Report in response to guidelines established by the Financial Stability Board's TCFD recommendations, including information on all four TCFD categories (governance, strategy, risk management, and metrics and targets).

3.10Credit Ratings

The following chart shows credit ratings issued to the Corporation and currently in effect.1

S&P3

DBRS4

Fitch5

Moody's

AQN - Issuer rating

BBB

AQN - Preferred Shares

P-3
(high)

Pfd-3

AQN - 2018 Subordinated Notes

BB+

AQN - 2019 Subordinated Notes

BB+

AQN – Equity Units

BB+ (Units)

BBB (Notes)

AQN – 2022-A Subordinated Notes

BB+

AQN – 2022-B Subordinated Notes

BB+

APCo - Issuer rating

BBB

APCo - Senior unsecured debt

BBB

Liberty Utilities Canada - Issuer Rating

BBB

Liberty Utilities Canada - Senior unsecured debt

BBB

Liberty Utilities - Issuer rating

BBB

Baa2

Liberty Utilities - Commercial Paper

A-2

Liberty Utilities Finance GP1 - Issuer rating2

BBB

BBB
(high)

Baa2

Liberty Utilities Finance GP1 - Senior unsecured notes2

BBB
(high)

BBB+

Baa2

Liberty Utilities Finance GP1 – 2.050% senior unsecured notes3

BBB

BBB+

Baa2

Empire - Issuer rating

BBB

Baa1

Empire - First mortgage bonds

A-

Empire - Senior unsecured debt

BBB

Baa1

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1 Credit ratings are intended to provide investors with an independent measure of the credit quality of an issuer or issue of securities. Credit ratings are not a recommendation to buy, sell or hold securities of AQN or any of its subsidiaries and do not comment as to market price or suitability for a particular investor. There can be no assurance that a rating will remain in effect for any given period of time or that the rating will not be revised or withdrawn at any time by the rating agency.

2 Issued by Liberty Utilities Finance GP1 and guaranteed by Liberty Utilities.

3 In 2022, S&P revised its outlook on the Corporation, Liberty Utilities, APCo, Liberty Utilities Finance GP1 and Empire from stable to negative, noting a lack of certainty regarding the Corporation’s financing plan for the Kentucky Power Transaction beyond the 2021 Bought Deal Offering, which could expose the Corporation to execution risks related to the procurement of credit supportive funding. S&P also noted that the negative outlook incorporated the possibility of any material adverse regulatory requirements which may be necessary to close the Kentucky Power Transaction. S&P also affirmed its “BBB” issuer credit rating for each of the Corporation, Liberty Utilities, APCo, Liberty Utilities Finance GP1 and Empire. Finally, S&P placed its rating on Liberty Utilities Finance GP1’s senior unsecured debt on CreditWatch with negative implications to reflect its view of the potential for such debt to be structurally subordinated following the closing of the Kentucky Power Transaction. In 2022, S&P removed the "CreditWatch with negative implications" from Liberty Utilities Finance GP1’s senior unsecured debt. During the first quarter of 2023, S&P affirmed these ratings and outlook, noting that its negative outlook reflects the execution risk associated with the Corporation’s targeted $1 billion of asset sales announced on January 12, 2023.

4 In 2022, DBRS placed the Corporation’s “BBB” Issuer Rating and “Pfd-3” Preferred Shares ratings “Under Review with Developing Implications”. DBRS indicated that it viewed the Kentucky Power Transaction as a positive development from a business risk perspective due to the expected increase in the Corporation’s regulated assets and rate base and expected improvements in jurisdictional diversification and capital expenditure planning. Notwithstanding these potentially positive impacts, the “Under Review with Developing Implications” rating action reflected DBRS’s view that the Corporation’s financing plan for the Kentucky Power Transaction could increase the Corporation’s nonconsolidated leverage. Subsequent to year-end in February 2023, DBRS affirmed its existing ratings on AQN, APCo and Liberty Utilities Finance GP1 and removed AQN from “Under Review with Developing Implications”, updating the outlook to stable.

5 In 2022, Fitch affirmed (i) the existing issuer ratings of both the Corporation and Liberty Utilities, and (ii) all the security ratings of the Corporation, Liberty Utilities and Liberty Utilities Finance GP1. Fitch also noted that the rating outlooks for the Corporation and Liberty Utilities are stable and that the credit ratings of APCo are unaffected by the Kentucky Power Transaction. Fitch noted that it views the Kentucky Power Transaction to be neutral to the credit quality of the Corporation and Liberty Utilities, given the underlying credit quality of Kentucky Power, and what Fitch expects to be a relatively credit-supportive financing plan for the Kentucky Power Transaction. During the first quarter of 2023, Fitch affirmed its existing ratings and outlook.

S&P

S&P rates long-term debt instruments and issuers with ratings ranging from “AAA”, which represents an extremely strong capacity of an obligor to meet its financial commitment, to “D”, which means, in the case of an issue rating, that the issuer is in default or in breach of an imputed promise, and in the case of an issuer rating, that there is a general default and the obligor will fail to pay all or substantially all of its obligations as they become due. A rating of “A” by S&P denotes an obligation somewhat more susceptible to the adverse effects of changes in circumstances and economic conditions than obligations in higher-rated categories; however, the obligor's capacity to meet its financial commitments on the obligation is still strong. A rating of “BBB” by S&P denotes an obligor having adequate capacity to meet its financial commitments; however, adverse economic conditions or changing circumstances are more likely to weaken the obligor's capacity to meet its financial commitments. A rating of “BB” by S&P is included amongst a range of ratings determined to have significant speculative characteristics. An obligation rated “BB” is less vulnerable to nonpayment than other speculative issues; however, it faces major ongoing uncertainties or exposure to adverse business, financial, or economic conditions that could lead to the obligor having inadequate capacity to meet its financial commitments. S&P ratings from “AA” to “CCC” may be modified by the addition of a plus “+” or minus “-” sign to show relative standing within the major rating categories. The absence of either a plus “+” or minus “-” sign indicates that the rating is in the middle of the category.

S&P rates short-term debt instruments and issuers with ratings ranging from “A-1”, which represents a strong capacity of an obligor to meet its financial commitment, to “D”, which means that the issuer is in default or in breach of an imputed promise. A rating of “A-2” by S&P denotes an obligation somewhat more susceptible to the adverse effects of changes in circumstances and economic conditions than obligations in higher-rated categories; however, the obligor's capacity to meet its financial commitments on the obligation is still satisfactory.

S&P’s Canadian preferred share rating scale serves the Canadian financial markets by expressing preferred share ratings in terms of rating symbols that have been actively used in the Canadian market over a number of years. A S&P preferred share rating on the Canadian preferred share rating scale is a forward-looking opinion about the creditworthiness of an obligor with respect to a specific preferred share obligation issued in the Canadian market, relative to preferred shares issued by other issuers in the Canadian market. There is a direct correspondence between the specific ratings assigned on the Canadian preferred share scale and the various rating levels on S&P’s global preferred share rating scale. S&P’s Canadian preferred share rating scale ranges from “P-1”, which represents a very strong capacity of an obligor to meet its financial commitments, to “D”, which represents a general default and that the obligor that will fail to pay all or substantially all of its obligations as they become due. A preferred share rating of “P-3 (high)” is equivalent to a rating of “BB+” on S&P’s global scale (which is discussed above). Ratings from “P-1” to “P-5” may be modified by “high” and “low” grades which indicate relative standing within the major rating categories.

DBRS

DBRS rates debt instruments and issuers with ratings ranging from “AAA”, which represents debt instruments and issuers of the highest credit quality, to “D”, which represents debt instruments for which an issuer has filed under any applicable bankruptcy, insolvency or winding up statute or for which there is a failure to satisfy an obligation after the exhaustion of grace periods. A rating of “BBB” by DBRS denotes an obligor having adequate credit quality; the capacity for the payment of financial obligations is considered acceptable although it may be vulnerable to future events. All rating categories other than “AAA” and “D” also contain subcategories "(high)" and "(low)". The absence of either a “(high)” or “(low)” designation indicates that the rating is in the middle of the category.

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The DBRS preferred share rating scale ranges from “Pfd-1”, which represents a superior credit quality, supported by entities with strong earnings and balance sheet characteristics, to “D”, which represents that an issuer has filed under any applicable bankruptcy, insolvency or winding up statute or is in default per the legal documents. Preferred shares rated “Pfd-3” are of adequate credit quality. While protection of dividends and principal is still considered acceptable, the issuing entity is more susceptible to adverse changes in financial and economic conditions, and there may be other adverse conditions present which detract from debt protection. Each rating category may be denoted by the subcategories “high” and “low”. The absence of either a “high” or “low” designation indicates the rating is in the middle of the category.

Fitch

Fitch rates long-term debt instruments and issuers with ratings ranging from “AAA”, which represents the highest credit quality and denotes the lowest expectation of default risk, to, in the case of rating for the debt instruments themselves, “C” which indicates exceptionally high levels of credit risk, or, in the case of issuer ratings, “D”, which indicates an issuer that in Fitch’s opinion has entered into bankruptcy filings, administration, receivership, liquidation or other formal winding-up procedure or that has otherwise ceased business. A rating of “BBB” by Fitch indicates that expectations of default risk are currently low. The capacity for payment of financial commitments is considered adequate, but adverse business or economic conditions are more likely to impair this capacity. A rating of “BB” by Fitch indicates an elevated vulnerability to credit risk, particularly in the event of adverse changes in business or economic conditions over time; however, business or financial alternatives may be available to allow financial commitments to be met. Ratings from “AA” to “CCC” may be modified by the addition of a plus “+” or minus “-” sign to show relative standing within the major rating categories.

Fitch rates short-term debt instruments and issuers with ratings ranging from “F1”, which represents the highest short-term credit quality and indicates the strongest intrinsic capacity for timely payment of financial commitments, to “D”, which indicates a broad-based default event for an entity or the default of a short-term obligation. A rating of “F2” by Fitch indicates good intrinsic capacity for timely payment of financial commitments. Ratings of “F1” may be modified by the addition of a plus “+” to denote any exceptionally strong credit feature.

Moody’s

Moody’s rates long-term debt instruments and issuers with ratings ranging from “Aaa”, which represents obligations judged to be of the highest quality, subject to the lowest level of credit risk, to “C”, which represents an obligation typically in default, with little prospect for recovery of principal or interest. A rating of “A” by Moody’s denotes obligations judged to be upper-medium grade and subject to low credit risk, while a rating of “Baa” by Moody’s denotes obligations judged to be medium-grade and subject to moderate credit risk and as such may possess certain speculative characteristics. Moody’s appends numerical modifiers 1, 2 and 3 to each generic rating classification from Aa through Caa. The modifier 1 indicates that the obligation ranks in the higher end of its generic rating category; the modifier 2 indicates a mid-range ranking; and the modifier 3 indicates a ranking in the lower end of that generic rating category.

Short-term obligations and issuers thereof may carry a rating ranging from Prime-1 or “P-1”, which represents an issuer’s superior ability to repay short-term debt obligations, to “Prime-3” or “P-3”, which represents an issuer’s acceptable ability to repay short-term obligations. Issuers may also be rated “Not Prime” or “NP”, which represents that an issuer does not fall within any of the Prime rating categories.

The Corporation has made, or will make, payments to each of S&P, DBRS, Fitch and Moody’s in connection with the assignment of ratings to both the Corporation and its securities. In addition, the Corporation has made customary payments in respect of certain subscription services provided to the Corporation by S&P and Fitch during the last two years.

4.ENTERPRISE RISK FACTORS

The Corporation is subject to a number of risks and uncertainties, certain of which are described in more detail below. The actual effect of any event on the Corporation’s business could be materially different from what is anticipated or described below. The description of risks below does not include all possible risks. See AQN’s MD&A for the year ended December 31, 2022 for additional risks that it faces.

Led by the Chief Compliance and Risk Officer, the Corporation has an established enterprise risk management, or ERM, framework. The Corporation’s ERM framework follows the guidance of ISO 31000 and the COSO Enterprise Risk Management – Integrated Framework. The Corporation’s ERM Policy details the Corporation’s risk management processes and risk governance structure.

As part of the risk management process, risk registers have been developed across the organization through ongoing risk identification and risk assessment exercises facilitated by the Corporation’s internal ERM team. Key risks and associated mitigation strategies are reviewed by the executive-level Enterprise Risk Management Council and are presented to the Board’s Risk Committee periodically.

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impact of a potential risk. However, there can be no assurance that the Corporation’s risk management activities will be successful in identifying, assessing or mitigating the risks to which the Corporation is subject.

4.1Risk Factors Relating to Operations

The Corporation’s operations involve numerous risks which, if they materialize, could disrupt or adversely affect its business, results of operations, financial position and cash flows.

The Corporation’s ability to safely and reliably operate, maintain, construct and decommission (as applicable) its power generation facilities, utility systems and other assets involve a variety of risks customary to the power and utilities sectors, many of which are beyond the Corporation’s control, including those that arise from:

•severe weather conditions and natural disasters;

•global climate change;

•environmental contamination/wildlife impacts;

•casualty or other significant events such as fires, explosions, security breaches or drinking water contamination;

•critical equipment breakdown or failure;

•increased competition;

•commodity supply and transmission constraints or interruptions;

•workplace and public safety events;

•infectious diseases, pandemics and similar public health threats, such as COVID-19;

•loss of key personnel;

•labour disputes;

•employee performance/workforce effectiveness;

•improper, illegal or erroneous acts of employees, contractors, vendors or other third parties;

•demand (including seasonality);

•loss of key customers;

•reduction in the price received for goods/services;

•reliance on transmission systems and facilities operated by third parties;

•land use rights/access;

•supply chain disruptions;

•lower-than-expected levels of efficiency or operational performance;

•acts by third parties, including cyber-attacks, criminal acts, physical security breaches, information security breaches, vandalism, war and acts of terrorism;

•the reduction, elimination or expiration of beneficial government subsidies, credits or incentives;

•projects with a limited operating history;

•opposition by external stakeholders, including local groups, communities and landowners;

•commodity price fluctuations and inflation;

•the availability of, and pricing for, alternative power or fuel sources;

•the performance of newly developed technologies;

•obligations to serve utility customers within its certificated service territories;

•the Corporation’s reliance on subsidiaries; and

•the Corporation’s reliance on acquisition counterparties.

These and other operating events and conditions could result in service and operational disruptions and may reduce the Corporation’s revenues, increase costs or both, and may materially affect its business, results of operations, financial position, valuation and cash flows, particularly if a situation is not resolved in a timely manner or the financial impacts of restoration are not alleviated through insurance policies or regulated rate recovery.

The Corporation’s generation, distribution and transmission assets may be negatively impacted by changes in general economic, credit, social and market conditions.

The Corporation’s generation, distribution and transmission assets are affected by energy and water demand, sales and operating costs, among other things, in the jurisdictions in which they operate. Demand, sales, and operating costs may change as a result of, among other things, fluctuations in general economic conditions, energy and commodity prices, inflation, interest rates, employment levels, personal disposable income, customer preferences, advancements in new technologies, population or demographic changes and housing starts. Significantly reduced energy or water demand in the Corporation’s service territories could reduce capital spending forecasts, and specifically capital spending related to new customer growth. A reduction in capital spending could, in turn, affect the Corporation’s rate base and earnings growth. A downturn in economic conditions may have an adverse effect on the Corporation’s results of operations, financial condition, and cash flows despite regulatory measures, where applicable, available to compensate for some or

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all of the reduced demand and increased costs, and which recovery, if any, may lag costs incurred by the Corporation. In addition, an extended decline in economic conditions could make it more difficult for customers to pay for the utility services they consume, thereby affecting the aging and collection of the utilities’ trade receivables.

Energy conservation, energy efficiency, distributed generation, community choice aggregation, technology, regulatory policies and other factors that reduce energy and water demand could adversely affect the Corporation’s business, financial condition and results of operations.

The emergence of initiatives designed to reduce greenhouse gas emissions and control or limit the effects of climate change has resulted in incentives and programs to increase energy efficiency and reduce water and energy consumption, including efforts to reduce the availability and reliance on natural gas. There may also be efforts to move to deregulation in certain of the markets in which the Regulated Services Group operates, which could adversely affect the Corporation’s business, financial condition and results of operations.

Significant technological advancements are taking place in the generation and utility industry, including advancements related to self-generation and distributed energy technologies such as fuel cells, micro turbines, battery storage, wind turbines, solar panels and technologies related to lower energy, natural gas and water use. Adoption of these and other technologies may increase as a result of government subsidies or policies, improving economics and changing customer preferences. Increased adoption of these practices, requirements and technologies could reduce demand for utility-scale electricity generation and electric, water, and natural gas distribution, and as a result, the Corporation’s business, financial condition and results of operations could be adversely affected.

The Corporation may also invest in and use newly developed, less proven, technologies or generation methods in its development and construction projects or in maintaining or enhancing its existing operations and assets. There is no guarantee that such new technologies will perform as anticipated. The failure of a new technology or generation method to perform as anticipated may adversely affect the profitability of a particular development project or existing operations and assets.

The Corporation and its facilities, operations and personnel are exposed to the effects of severe weather, natural disasters, diseases, pandemics, and other catastrophic and force majeure events beyond the Corporation’s control, and such events could result in a material adverse effect on the Corporation.

The Corporation’s facilities and operations are exposed to potential interruption and damage, and partial or full loss, resulting from environmental disasters, other seismic activity, equipment failures, severe weather, natural and man-made disasters, diseases, pandemics, and other catastrophic and force majeure events. There can be no assurance that in the event of an earthquake, hurricane, tornado, fire, flood, ice storm, tsunami, typhoon, geomagnetic storm, electromagnetic pulse, terrorist attack, cyber-attack, act of war or other natural, man-made or technical catastrophe, all or some parts of the Corporation’s generation facilities and infrastructure systems will not be disrupted or that project development or construction delays or injuries will not occur. The occurrence of such an event may not release the Corporation from performing its obligations pursuant to Offtake Contracts or other agreements with third parties. The occurrence of a significant event which disrupts the ability of the Corporation to provide utility services, or for its power generation assets to produce or sell power for an extended period, including events which preclude existing customers under Offtake Contracts from purchasing electricity, could have a material negative impact on the Corporation’s business. In addition, certain of the Corporation’s utilities operate in remote and/or mountainous terrain, including islands, where the Corporation’s facilities are at increased risk of loss or damage from fires, floods, washouts, landslides, earthquakes, hurricanes, tornadoes, avalanches and other acts of nature.

Wildfires may occur within the Corporation’s service territories, including, without limitation, in California and the southern United States, such as the Mountain View fire that occurred on November 17, 2020 within the CalPeco Electric System’s service territory in California. The Corporation’s facilities have the potential to cause fires as a result of equipment breakdown or failure, trees falling on, and lightning strikes to, distribution lines or equipment, and other causes. If it is accused or found to be responsible for such a fire, the Corporation could suffer costs, losses and damages, all or some of which may not be recoverable through insurance, legal, regulatory cost recovery or other processes and could materially affect the Corporation’s business, results of operations and cash flows, including its reputation with customers, regulators, governments and financial markets. Resulting costs could include fire suppression costs, fines, regeneration, timber value, asset replacement costs, inverse condemnation, increased insurance costs and costs arising from damages and losses incurred by third parties, including punitive damages.

AQN is subject to the risks associated with an outbreak of infectious disease, a pandemic or a similar public health threat.

A local, regional, national or international outbreak of a contagious disease, pandemic or similar public health threat, or a fear of any of the foregoing, including, but not limited to, the ongoing COVID-19 pandemic, could result in restrictive measures being taken by the Corporation or various governments and businesses which may result in additional risks and uncertainties to AQN’s business, operations and financial condition.

The extent of the effect of the disease, pandemic or public health threat on AQN’s operational and financial performance will depend on numerous factors, including the duration, spread and intensity of the outbreak, the actions by governments and others taken to contain the outbreak or mitigate its impact and changes in the preferences of consumers, all of which are uncertain and difficult to predict as such factors evolve rapidly over the course of any such event or public health threat. Certain aspects of AQN’s business and operations that have been or could potentially

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continue to be impacted by the outbreak of any disease, pandemic or public health threat include increased operating costs (which AQN may not be able to recover through future rates), delays or longer-term stoppage of development projects, temporary or long-term labour shortages or disruptions, temporary or long-term impacts on domestic and global supply chains, impairments and/or write-downs of assets, decreased demand for electricity and natural gas, impacts on the timing and extent of capital expenditures, increased credit risk and counterparty risks, delayed collection of accounts receivable, increased market volatility and the deterioration of worldwide credit and financial markets that could limit AQN’s ability to access capital and financing on acceptable terms or at all. Any such impact could have a material adverse effect on the Corporation’s business, operations and financial condition.

With respect to the COVID-19 pandemic in particular, while certain pandemic-related risks are receding and restrictions to contain the spread of the virus have lifted in many regions, the pandemic continues to have, and a new disease outbreak could have, an impact on the global economy, including contributing to high levels of inflation, supply chain issues, rising interest rates and the resulting threat of recession. In addition, public health measures continue to be implemented in certain regions or countries and may be reinstated in other areas.

The Corporation may experience critical equipment breakdown or failure, safety events or other operating events, which could have a material adverse effect on the Corporation’s business, financial condition, results of operations and reputation.

The Corporation’s facilities are subject to the risk of critical equipment breakdown or failure, safety shutdowns and lower-than-expected levels of efficiency or operational performance due to the deterioration of assets from use or age, design flaws and related design modification requests from original equipment manufacturers and service providers or errors in the operation or maintenance of these facilities, among other things. These and other safety and operating events and conditions could result in bodily injury or death, property damage, the release of hazardous substances, increased capital expenditures, reduced production and service disruptions and, to the extent that a facility’s equipment requires longer than forecasted down times for maintenance and repair, or suffers disruptions of power generation, distribution or transmission for other reasons, the Corporation’s business, operating results, financial condition, reputation or prospects could be adversely affected. In addition, a portion of the Corporation’s infrastructure is located in remote areas, which may make access to perform maintenance and repairs difficult if such assets become damaged.

Such events could, among other things, potentially cause dam failures or drowning that could impact the Corporation’s hydroelectric facilities, and result in a loss of generating capacity, damage to the environment or damage and harm to third parties or the public, including as a result of the flow of large amounts of water causing flooding upstream or downriver. There are inherent hazards and operation risks in electric generation and distribution and natural gas distribution activities, such as electric contact, leaks, accidental explosions and mechanical problems that could cause the loss of human life, significant damage to property, environmental pollution and impairment of operations. Water and wastewater distribution systems operate under pressurized conditions within pressure ranges approved by regulators. Should a water distribution network become compromised or damaged, the resulting release of pressure could result in serious injury or death to individuals or damage to property. In addition, water contamination in a drinking water distribution system could result in severe illness or death to those who drink the contaminated water. During periods of high rainfall, certain sewage networks may become saturated, including ESSAL’s, which may result in mixed waters flowing onto the public highway and/or activating the emergency spillways, and by operating at an increased or maximum capacity, the sewage system may be subject to increased deterioration over time.

The Corporation is subject to the risks associated with climate change and weather, as well as government and societal responses thereto, that may result in a material adverse effect on the Corporation.

The Corporation is subject to risks that arise or may arise from the impacts of climate change that may result in a material adverse effect on the Corporation. In addition to the current risks faced by the Corporation from climate change, the Corporation is subject to the transitional risk of climate change, including changing weather and regulations and increasing public concern about climate change and growing support for reducing carbon emissions. City, state, provincial, federal and local governments have been setting policies and enacting laws and regulations to deal with climate change impacts in a variety of ways, including de-carbonization initiatives and promotion of cleaner energy and renewable energy generation of electricity. Insurance companies are also evaluating the impacts of climate change which may result in fewer insurers, more restrictive coverage, and increased premiums.

Weather and Physical Risks

Climate change is predicted to lead to increased frequency and intensity of weather events and related impacts such as storms, wildfires, ice storms, tornadoes, hurricanes, cyclones, heavy rainfall, heavy snowfall, extreme winds, water availability and quality, flooding, sea level rise, storm surge and other changing weather patterns. To the extent the frequency and intensity of extreme weather events and storms increase as a result of climate change, the Corporation’s capital costs, cost of maintenance and cost of providing service may increase, including the costs and the availability of procuring insurance related to such impacts.

Climate change, including extreme weather events, create a risk of physical damage to the Corporation’s assets, which may negatively impact the Corporation’s ability to reliably provide services and production. High winds can damage structures and cause widespread damage to transmission and distribution infrastructure. Increased frequency and severity of weather events increases the likelihood that the duration of power outages and energy, fuel and water supply disruptions could increase. With respect to the Corporation’s wind facilities, ice can accumulate on wind turbine blades in the winter months, which can have a significant impact on energy yields, and could result in wind turbines

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experiencing down time. Increased rainfall or intensity of flooding could adversely affect the operations of the Corporation’s hydroelectric generating facilities as well as impact the Corporation’s water systems. The potential impacts of climate change, such as rising sea levels and larger storm surges from more intense hurricanes, can combine to produce greater damage to facilities located near coasts or on islands. Additionally, extreme weather conditions may increase the cost of maintaining the Corporation’s systems, and can contribute to increased system stress, including service interruptions. Weather conditions outside of the Corporation’s service territory could also have an impact on revenues. The Corporation may buy and sell electricity depending upon its needs and market opportunities. Extreme weather conditions creating high energy demand on the Corporation’s own and/or other systems and facilities may raise market electricity prices as the Corporation buys short-term energy to serve its own systems and facilities, or to satisfy its contractual energy delivery obligations. Such climate change risks may also impact third parties on which the Corporation relies, such as suppliers and services providers, resulting in delays and increased costs of providing goods or services.

Climate change is also characterized by increases in global air temperatures. Increased air temperatures may bring increased frequency and severity of wildfires, including within the Corporation’s service territories. Increased air temperatures could also result in decreased efficiencies over time of both generation and transmission facilities. Changes in precipitation due to climate change that result in droughts could also increase the risk of wildfire. If it is found to be responsible for such a fire, the Corporation could suffer costs, losses and damages, all or some of which may not be recoverable through insurance, legal, regulatory cost recovery or other processes and could materially affect the Corporation’s business, results of operations and cash flows, including its reputation with customers, regulators, governments and financial markets.

Generation and Customer Consumption Risks

The Corporation operates hydroelectric generation and water distribution businesses in certain of its markets. Such businesses depend on availability of water. Changes in precipitation patterns, water table levels, water temperatures and ambient air temperatures could adversely affect the availability of water and consequently the output from such facilities.

In addition, changes in intensity of wind resources due to climate change could impact the Corporation’s wind generation facilities and increased seasonal irradiance variance caused by climate change could impact the Corporation’s solar generation facilities.

Customers’ energy needs vary significantly in response to weather conditions, primarily temperature and humidity. For residential customers, heating and cooling represent their largest energy use. To the extent weather conditions are affected by climate change, customers’ energy use could increase or decrease depending on the duration and magnitude of the changes, which may adversely affect the Corporation’s business, results of operations and cash flows. Further, changes in attitudes towards reducing the impacts of climate change may also result in the reduction of energy and water use by the Corporation’s customers.

Additionally, to the extent climate change negatively impacts a region’s economic health, it may also negatively impact the Corporation’s revenues as the Corporation’s financial performance depends in part on the health of the regional economies that it serves.

Reputational Risks

Failure to address issues related to climate change or to achieve any greenhouse gas emissions reduction and other sustainability goals may affect the Corporation’s reputation with stakeholders, its ability to operate and grow, its access to, and cost of, capital or insurance, the confidence of investors and customers who may seek more sustainable products and services, and the ability to recruit and retain employees.

In addition, all of the electricity generated by Kentucky Power is produced by the combustion of fossil fuels. As a result, the Kentucky Power Transaction could result in reputational harm to the Corporation and adversely affect perceptions regarding the Corporation’s commitment to environmental and sustainability matters, as well as the Corporation’s ability to accomplish its environmental and sustainability objectives.

Conversely, the Corporation’s commitment to environmental and sustainability matters may affect the Corporation’s reputation with pro-fossil fuel governments and stakeholders, impacting its ability to operate, obtain capital, grow or carry out its strategic plans.

Regulatory Risks

Changing carbon-related costs, policy and regulatory changes and shifts in supply and demand factors could lead to more expensive or scarcer products and services that are required by the Corporation in its operations. This could lead to supply shortages and delivery delays as well as the need to source alternate products and services.

Government and regulatory initiatives, including greenhouse gas emissions standards, air emissions standards, water conservation programs and climate change related disclosure requirements are being proposed and adopted in many jurisdictions in response to concerns regarding the effects of climate change. In some jurisdictions, government policy has included carbon pricing, emissions limits, and cap and trade mechanisms. Over the medium and longer terms, this could potentially lead to a significant portion of hydrocarbon infrastructure assets being subject to additional regulation and limitations in respect of greenhouse gas emissions and operations. Early closure of the Corporation’s owned and jointly owned electric generating facilities due to environmental risks, litigation or public policy changes could have a material adverse impact on the Corporation’s results of operations and liquidity. Conversely, government and regulatory

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initiatives designed to support the fossil-fuel industry could impair the Corporation’s ability to pursue its strategic plans, such as “greening the fleet” initiatives, or otherwise impact the Corporation’s operations or ability to obtain financing, which could have a material adverse impact on the Corporation’s results of operations or liquidity.

Compliance and Other Costs

The Corporation may be required to comply with existing or new climate-related and environmental legislative and regulatory requirements, and may be subject to other emission reduction pressures, including its own targets. Such legislative and regulatory initiatives and other pressures could adversely affect the Corporation’s operations and financial performance over time. Depending on the regulatory response to government legislation and regulations, the Corporation may be exposed to the risk of reduced recovery through rates or “regulatory lag” in its Regulated Services Group in respect of such compliance costs, or may be required to take other actions in the case where costs may not be fully recoverable, or at all.

Litigation and Activism Risk

The Corporation could face litigation or regulatory action as a result of climate change, including related to environmental harm from carbon emissions or impacts from the Corporation’s facilities, damage caused to customers or other third parties by the Corporation’s utility systems as a result of weather and/or climate change, or inaccurate or inadequate climate change and other environmental, social and governance (ESG) public disclosure. The Corporation may also face shareholder proposals and activism-related ESG issues that may detract management’s attention from the Corporation’s day to day operations, affect public perceptions of the Corporation, and result in increased costs in response to such matters.

Risks related to technology systems, including the upgrading of certain technology infrastructure systems by the Corporation, could adversely affect the Corporation’s operations, financial condition, cash flows and results of operations.

The Corporation relies upon various information and operational technology infrastructure systems to carry out its business processes and operations. This subjects the Corporation to inherent costs and risks associated with maintaining, upgrading, replacing and changing information and operational technology systems. This includes impairment of its technology systems, potential disruption of operations, business process and internal control systems, substantial capital expenditures, demands on management time and other risks of delays, and difficulties in upgrading, transitioning and integrating technology systems.

AQN and certain of its subsidiaries are in the process of updating their technology infrastructure systems through the implementation of an integrated customer solution platform, which is expected to include customer billing, enterprise resource planning systems and asset management systems. The implementation of these systems is being managed by a dedicated team. Following successful pilot implementations, deployment began in 2022 and is expected to occur in a phased approach across the enterprise through 2024. The implementation of such technology systems will require the investment of significant financial and human resources. Disruptions, delays or deficiencies in the design, implementation, or operation of these technology systems or integration of these systems with other existing information technology or operations technology could: adversely affect the Corporation’s operations, including its ability to monitor its business, pay its suppliers, bill its customers, and report financial information accurately and on a timely basis; lead to higher than expected costs; lead to increased regulatory scrutiny or adverse regulatory consequences; or result in the failure to achieve the expected benefits. As a result, the Corporation’s operations, financial condition, cash flows and results of operations could be adversely affected.

Security breaches, criminal activity, theft, terrorist attacks, cyber-attacks and other threats or incidents relating to the Corporation’s information security could directly or indirectly interfere with the Corporation’s operations, could expose the Corporation or its customers or employees to risk of loss, and could expose the Corporation to liability, regulatory penalties, reputational damage and other harm to its business.

The Corporation relies upon its and third-party information and operational technology networks, systems and devices to process, transmit and store electronic information, and to manage and support a variety of business processes and activities and safely operate its assets. The Corporation also uses its and third-party information technology systems to record, process and summarize financial information and results of operations for internal reporting purposes and to comply with financial reporting, legal and tax requirements. The Corporation’s and certain of its third-party vendors’ technology networks, systems and devices collect and store sensitive data, including system operating information, proprietary business information belonging to the Corporation and third parties, as well as personal information belonging to the Corporation’s customers, employees, and other stakeholders. As the Corporation operates critical infrastructure, it may be at an increased risk of cyber-attacks or other security threats by third parties. The Corporation’s, its third-party vendors’ or other counterparties’ technology systems and technology networks, devices and infrastructure may be vulnerable to damage, disruptions or shutdowns due to attacks by hackers or breaches due to employee error or malfeasance, disruptions during software or hardware upgrades, telecommunication failures, theft, politically-driven attacks (including as a result of the conflict between Russia and Ukraine, and any associated sanctions imposed or actions taken by the United States, Canada or other countries or retaliatory measures by Russia), acts of war or terrorism, natural disasters or other similar events. In addition, certain sensitive information and data may be stored by the Corporation on physical devices, in physical files and records on its premises or transmitted to the Corporation verbally, subjecting such information and data to a risk of loss, theft, release and misuse. Methods used to attack critical assets could include general purpose or industry-specific malware delivered via network transfer, removable media, viruses,

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attachments, or links in e-mails. The methods used by attackers are continuously evolving and can be difficult to predict and detect. The occurrence of any of these events could negatively impact the Corporation’s operations, power generation facilities and utility distribution and transmission systems; could cause services disruptions or system failures; could adversely affect safety; could expose the Corporation, its customers or its employees to a risk of loss or misuse of information; could affect the ability to earn or collect revenue or correctly record, process and report financial information; and could result in increased costs, legal claims or proceedings, liability or regulatory penalties against the Corporation, damage the Corporation’s reputation or otherwise harm the Corporation’s business.

The long-term impact of terrorist attacks and cyber-attacks and the magnitude of the threat of future terrorist attacks and cyber-attacks on the utility and power generation industries in general, and on the Corporation in particular, cannot be known. Increased security measures to be taken by the Corporation as a precaution against possible terrorist attacks and cyber-attacks may result in increased costs to the Corporation. The Corporation must also comply with data privacy laws in each of the jurisdictions in which it operates. Certain data privacy laws and other cybersecurity regulations have expanded in recent years, leading to increased obligations, and fines for breaches of such laws and regulations have increased. The Corporation may incur additional costs to maintain compliance, or significant financial penalties, in the event of a breach.

The Corporation cannot accurately assess the probability that a security breach may occur or accurately quantify the potential impact of such an event. The Corporation provides no assurance that it will be able to identify, protect against and remedy all cybersecurity, physical security or system vulnerabilities or that unauthorized access or errors will be identified and remedied. Should a breach occur, the Corporation may suffer costs, losses, and damages, all or some of which may not be recoverable through insurance, legal, regulatory, or other processes, and could materially adversely affect the Corporation’s business and results of operations including its reputation with customers, regulators, governments, and financial markets. Resulting costs could include, among others, response, recovery (including ransom costs), and remediation costs, increased protection or insurance costs, and costs arising from damages and losses incurred by third parties.

Risks including but not limited to any physical security breach, terrorist attacks, military campaigns, unauthorized access, electricity or equipment theft and vandalism could adversely affect the Corporation’s business and its operations.

A physical attack on the Corporation’s generation, transmission or distribution assets could interfere with its normal business operations and affect its ability to control such assets. A physical security intrusion could lead to theft, vandalism, harm to employees or the release of critical operating information, which could adversely affect the Corporation’s operations or adversely impact its reputation, and could result in significant costs, fines and litigation. Strategic targets, such as energy and water assets, may be at greater risk of attack than other targets.

Uncertainty surrounding continued hostilities or sustained military campaigns (including as a result of the conflict between Russia and Ukraine, and any associated sanctions imposed or actions taken by the United States, Canada or other countries or retaliatory measures by Russia) may affect operations of the Corporation in unpredictable ways, including disruptions of supplies and markets for products of the Corporation, and the possibility that the Corporation’s operations or facilities could be direct targets of, or indirect casualties of, an act of terror or cyber-security attack. The effects of hostilities, military campaigns, or terrorist or cyber-security attacks could include disruption to the Corporation’s generation, transmission and distribution systems or to the electrical grid in general, and could result in a decline in the general economy and have a material adverse effect on the Corporation.

The loss of key personnel, the inability to hire and retain qualified employees, and labour disruptions could adversely affect the Corporation’s business, financial position and results of operations.

The Corporation’s operations depend on the continued efforts of its employees. Hiring and retaining key employees, including employees required for critical functions, and maintaining the ability to attract new skilled employees are important to the Corporation’s operational and financial performance. The Corporation cannot guarantee that any member of its management or any one of its key employees will continue to serve in any capacity for any particular period of time or that any leadership transitions will be successful.

Certain events or conditions, such as competition with other potential employers, an aging workforce, epidemic, pandemic (including COVID-19) or similar public health emergency, lack of diversity, mismatch of skill set or complement to future needs, or unavailability of contract resources may lead to operating challenges, labour disruption, increased risk of liability and increased costs. The challenges the Corporation might face as a result of such risks include a lack of resources, an increase in safety risks, potential negative impacts to diversity, equity and inclusion efforts, losses to its knowledge base and the time required to develop new workers’ skills. In any such case, costs, including costs for contractors to replace employees, productivity costs, and safety costs may rise. If the Corporation is unable to successfully attract and retain an appropriately qualified workforce, its financial position or results of operations could be negatively affected.

The maintenance of a productive and efficient labour environment without disruptions cannot be assured. In the event of a strike, work stoppage or other form of labour disruption, the Corporation would be responsible for procuring replacement labour and could experience disruptions in its operations and incur additional expense. Further, an increase in the number of collective bargaining agreements or the inability to maintain or negotiate future agreements on acceptable terms could impact the Corporation’s reputation or result in higher labour costs or work disruptions.

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The Corporation’s revenues and results of operations are affected by seasonal fluctuations and year to year variability in weather conditions and natural resource availability.

The Corporation is subject to risks associated with seasonal fluctuations and year to year variability in weather conditions and natural resource availability, which affect the quantity of electric power generated, and sold by the Corporation, the availability of water to be distributed by the Regulated Services Group and the demand for the utility services of the Regulated Services Group.

The Regulated Services Group’s water distribution operations depend on an adequate supply of water to meet present and future demands of customers. Drought conditions could interfere with sources of water supply used by the utilities and affect their ability to supply water in sufficient quantities to existing and future customers. An interruption in the water supply could have an adverse effect on the results of operations of these utilities. Demand for electricity, water and natural gas from the Regulated Services Group’s utility distribution systems is affected by weather conditions and temperature. Demand for water may decrease if there is above normal rainfall or rainfall is more frequent than normal, or if government restrictions are imposed on water usage during drought conditions. Demand for electricity and natural gas are also subject to significant seasonal variation, year-to-year variations and changes in weather patterns.

Please see “Description of the Business – Renewable Energy Group – Cycles and Seasonality” and “Description of the Business – Regulated Services Group – Cycles and Seasonality” for a description and discussion of these risks.

The Corporation historically has entered, and may in the future, enter into long-term Offtake Contracts and derivative contracts to reduce the risk of fluctuations in electricity prices, which contracts could give rise to performance and financial risks and could result in significant costs to the Corporation.

The Renewable Energy Group sells a significant portion of the energy, capacity and RECs it generates under long-term Offtake Contracts. The Renewable Energy Group also enters into financial or physical power hedges to reduce the risk from fluctuations in market price. For instance, several of the Renewable Energy Group’s wind energy production facilities are subject to long-term hourly energy price hedges for a portion of their expected energy production. The Corporation may incur significant costs in establishing or terminating Offtake Contracts or may be unable to benefit from favourable changes in market price as a result of these Offtake Contracts, including where external price and cost factors, such as inflation or interest rate fluctuations, are not passed through the Offtake Contract to the counterparty.

In addition, the Corporation may not be able to generate power in the amounts or at the times required by the applicable Offtake Contract, due to the variable nature of the natural resource (for renewable power generation) or due to transmission grid curtailments, mechanical failures, weather events or other reasons. Because of this risk, the Corporation typically does not hedge the full expected production of a particular facility, which leaves a portion of expected production subject to market price risk. In addition, production shortfalls (relative to hedged production volumes) may force the Renewable Energy Group to purchase power in the merchant market at prevailing rates to settle against the applicable hedge contract. Such factors could materially and adversely affect the Corporation’s results of operations and cash flows, depending on both the amount of shortfall and the market price of electricity at the time of the shortfall.

Any requirement for the Corporation to post letters of credit or other margin cash collateral under any of its derivative instruments or similar instruments could have a material adverse effect on the Corporation’s business, financial condition and results of operations. These risks may be increased during periods of adverse market or economic conditions. Additionally, the Corporation is unable to assure that these derivative instruments will be effective to protect against material adverse effects on the Corporation’s business, financial condition and results of operations.

The Corporation’s facilities rely on national and regional transmission systems and other commodity transportation facilities that are owned and operated by third parties and have both regulatory and physical constraints that could impede access to electricity markets or other commodity markets.

A substantial portion of the Corporation’s power generation facilities depend on electric transmission systems and related facilities owned and operated by third parties to deliver the electricity the Corporation generates to delivery points where ownership changes and the Corporation is paid. These grids operate with both regulatory and physical constraints which in certain circumstances may impede access to electricity markets. There may be instances following system studies, in system emergencies, chronic weather events, system mismanagement or after other system issues in which the Corporation’s power generation facilities are physically disconnected from the power grid, or their production curtailed, for periods of time. Most of the Corporation’s electricity sales contracts do not provide for payments to be made if electricity is not delivered.

The power generation facilities of the Corporation may also be subject to changes in regulations governing the cost and characteristics of use of the transmission and distribution systems to which its power generation facilities are connected. In the future, these power generation facilities may not be able to secure access to interconnection or transmission capacity at reasonable prices, in a timely fashion or at all, which could then cause delays and additional costs in attempting to negotiate or renegotiate Offtake Contracts, complete construction projects, construct new projects or operate existing projects. Any such increased costs and delays could delay the commercial operation dates of the Corporation’s new projects and negatively impact the Corporation’s revenues and financial condition.

Certain of the Corporation’s subsidiaries depend upon natural gas and other commodity transportation facilities, many of which they do not own. Occurrences affecting the operation of these facilities may be beyond the control of the Corporation’s subsidiaries (such as severe weather, a pipeline rupture or cybersecurity or physical events rendering

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pipeline facilities unavailable) and may limit or halt their ability to sell and deliver natural gas or other commodities and generate electricity, which could materially adversely impact the Corporation’s business, financial condition and results of operations.

The Corporation does not own the land on which many of its projects are located and its use and enjoyment of real property rights for its projects may be adversely affected by the rights of lienholders and leaseholders, which could have a material adverse effect on its business, results of operations, financial condition and cash flows.

The Corporation does not own all of the land on which its projects are located. Such projects generally are, and future projects may be, located on land occupied under long-term easements, leases, and rights of way. The ownership interests in the land subject to these easements, leases and rights of way may be subject to mortgages securing loans or other liens and other easements, lease rights and rights of way of third parties that were created previously. As a result, some of the rights under such easements, leases or rights of way held by the Corporation may be subject to the rights of these third parties, and the rights of the Corporation to use the land on which its projects are or will be located and its rights to such easements, leases and rights of way could be lost or curtailed. Any such loss or curtailment of the rights of the Corporation to use the land on which its projects are or will be located could have a material adverse effect on its business, results of operations, financial condition, and cash flows.

Disruption, delays and excess costs in the Corporation’s supply chain may have a material adverse effect on the Corporation’s business, results of operations, financial condition and cash flows.

The Corporation’s ability to operate effectively is in part dependent upon access to, and the provision of, equipment, materials and services in a timely manner. Loss or delay of key equipment, materials and service suppliers, the provision of key equipment, materials and services at higher than expected or budgeted costs, and the reputational and financial risk exposures of key vendors, including as a result of changes in laws, regulations and standards, inflation, tariffs, transportation delays, delays in approvals, customs issues and COVID-19, could affect the Corporation’s operations and timing, execution, viability and profitability of capital projects and could result in project development and construction delays (which may cause the Corporation to pay liquidated damages or other penalties or amounts), disruptions, and cost overruns or otherwise adversely impact the Corporation’s financial condition.

The modification, reduction, elimination or expiration of government subsidies, credits or incentives could adversely affect the Corporation’s prospects for growth and its results of operations, financial condition and cash flows.

The Corporation seeks to take advantage of government policies that promote renewable power generation and enhance the economic feasibility of renewable power projects. Renewable power generation sources currently benefit from various incentives in the form of feed-in tariffs, rebates, tax credits and other incentives throughout the markets in which the Corporation participates or intends to participate. The modification, removal or phasing out of any such policies or laws could adversely affect the viability of certain of the Corporation’s expected growth initiatives or renewable energy projects, and could adversely affect the Corporation’s results of operations, financial condition and cash flows.

The Corporation’s portfolio includes development and constructions projects, as well as recently completed projects that have a limited operating history. Such projects may not perform as expected.

The Corporation’s portfolio includes development and constructions projects, as well as recently completed projects that have recently commenced operations and therefore have a limited operating history. As a result, the assumptions and estimates regarding the performance of these projects are and will be made without the benefit of a meaningful operating history. The ability of such projects to perform as expected will also be subject to risks inherent in newly constructed generation and transmission projects, including, but not limited to, equipment performance below the Corporation’s expectations, unexpected component failures and product defects, and generation and transmission system failures and outages. The failure of some or all of the projects to perform as expected could have a material adverse effect on the Corporation’s business, results of operations, financial condition and cash flows.

The Corporation’s financial performance may be adversely affected by fluctuations in commodity prices, lower prices for alternative fuel sources or reductions in energy market liquidity.

Market prices for power, generation capacity, ancillary services and natural gas are unpredictable and tend to fluctuate substantially, which may affect the Corporation’s operating results. With respect to the Regulated Services Group, commodity price exposure is primarily limited to the cost of electricity and natural gas. Although the Regulated Services Group’s utility rates and tariffs are generally designed to allow recovery of commodity costs, timing differences and other factors, which may be exacerbated by fluctuating prices, may result in less than full recovery. Further, customers may change consumption patterns depending on the cost of alternative energy or fuel sources. Demand for the electrical energy generated by the Corporation’s electric generation assets is affected by the price and availability of other fuels, including, but not limited to, nuclear, coal and oil. To the extent renewable energy becomes less cost-competitive due to reduced or eliminated government renewable energy targets and other tax credits and incentives that favour renewable energy, cheaper alternatives or otherwise, demand for renewable energy could decrease. Slow growth or a long-term reduction in renewable energy demand could have a material adverse effect on the Corporation’s business, results of operations, financial condition and cash flows.

The Corporation is an active participant in energy markets. The liquidity of regional energy markets is an important factor in the Corporation’s ability to manage risks in these operations. Market liquidity is driven in part by the number of active market participants. Liquidity in the energy markets can be adversely affected by price volatility, restrictions on the

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availability of credit and other factors, and any reduction in the liquidity of energy markets could have a material adverse effect on the Corporation’s business, financial condition and results of operations.

Cash flow deferrals related to energy commodities can be significant.

The Corporation is permitted to collect from customers only amounts approved by regulatory commissions. However, the Corporation’s costs to provide utility services can be much higher or lower than the amounts currently billed to customers. The Corporation is permitted to defer income statement recognition and recovery from customers for some of these differences, which are recorded as deferred charges with the opportunity for future recovery through retail rates. These deferred costs are subject to review for prudence and potential disallowance by regulators, who have discretion as to the extent and timing of future recovery or refund to customers.

Power and natural gas costs higher than those recovered in retail rates reduce cash flows. Amounts that are not allowed for deferral or which are not approved to become part of customer rates affect the Corporation’s results of operations.

Even if the regulators ultimately allow the Corporation to recover deferred power and natural gas costs, the Corporation’s operating cash flows can be negatively affected until these costs are recovered from customers.

The Regulated Services Group is obligated to serve utility customers within its certificated service territories, which may require that the Corporation make capital expenditures and incur indebtedness to expand service to new customers.

The Regulated Services Group may have facilities located within areas experiencing growth. These utilities may have an obligation to service new residential, commercial and industrial customers. While expansion to serve new customers could result in increased future cash flows, it may require significant capital commitments in the immediate term, some or all of which may not be recoverable in rates. Accordingly, the Regulated Services Group may be required to obtain additional capital or incur additional borrowings to finance these future construction obligations.

As a holding company, AQN does not have its own operating income and must rely on the cash flows from its subsidiaries to pay dividends and make debt payments.

AQN is a holding company with no significant operations of its own, and AQN’s primary assets are shares or other ownership interests of its subsidiaries. AQN’s subsidiaries are separate and distinct legal entities and may have no obligation to pay any amounts to AQN, whether through dividends, loans or other means. The ability of t AQN’s subsidiaries to pay dividends or make distributions to the AQN depends on several factors, including each subsidiary’s actual and projected earnings and cash flow, capital requirements and general financial condition, regulatory restrictions, covenants contained in credit facilities to which they are parties, and the prior rights of holders of their existing and future secured debt and other debt or equity securities. Further, the amount and payment of dividends or distributions from any subsidiary is at the discretion of such subsidiary’s board, which may reduce or cease payment of dividends or distributions at any time. In addition, there may be changes to tax regulation affecting the repatriation of dividends from other countries, which may negatively affect AQN.

The Corporation is not able to insure against all potential risks and may become subject to higher insurance premiums, and the Corporation’s ability to obtain insurance and the terms of any available insurance coverage could be materially adversely affected by international, national, state or local events and company-specific events, as well as the financial condition of insurers.

The Corporation maintains insurance coverage for certain exposures, but this coverage is limited and the Corporation is generally not fully insured against all significant losses. Insurance coverage for the Corporation is subject to policy conditions and exclusions, coverage limits, and various deductibles, and not all types of liabilities and losses may be covered by insurance. Further, certain assets and facilities of the Corporation are not fully insured, as the cost of the coverage is not economically viable or is not otherwise available. Insurance may not continue to be offered on an economically feasible basis, or at all, and may not cover all events that could give rise to a loss or claim involving the Corporation’s assets or operations. There can also be no assurance that insurers will fulfill their obligations. The Corporation’s ability to obtain and maintain insurance and the terms of any available insurance coverage could be materially adversely affected by international, national, state or local events and company-specific events, as well as the financial condition of insurers.

If the Corporation were to incur a serious uninsured loss or a loss significantly exceeding the limits of its insurance policies, the results could have a material adverse effect on the Corporation’s business, results of operations, financial condition and cash flows. In the event of a large uninsured loss, including those caused by severe weather conditions, natural disasters and certain other events beyond the control of the Regulated Services Group, the Corporation may make an application to an applicable regulatory authority for the recovery of these costs through customer rates to offset any loss. However, the Corporation cannot provide assurance that the regulatory authorities would approve any such application in whole or in part. This potential recovery mechanism is not available to the Renewable Energy Group.

The Corporation is subject to litigation and administrative proceedings, which may adversely impact the Corporation’s consolidated financial position, results of operations and cash flows.

The Corporation is subject to legal proceedings, administrative proceedings, claims and other litigation, including class actions, that arise in the course of its business and activities. These actions may include contractual disputes, employment-related claims, securities-based litigation, claims from customers related to the services provided by the

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Corporation, claims for personal injury or property damage, public nuisance claims (including claims relating to emissions from coal or fossil fuel-based generation facilities), and actions by regulatory or tax authorities. The final outcome with respect to such legal proceedings cannot be predicted with certainty, and unfavourable outcomes or developments relating to these proceedings or future proceedings, such as judgments for monetary damages, injunctions, denial or revocation of permits or settlement of claims, could have an adverse effect on the Corporation’s financial condition, results of operations and cash flows. Such outcomes may not be covered by insurance. Even if the Corporation prevails in any such legal proceedings, the proceedings could be costly, time-consuming and divert the attention of management and other personnel, which could adversely affect the Corporation.

4.2Risk Factors Relating to Financing and Financial Reporting

A downgrade in AQN’s credit ratings or the credit ratings of its subsidiaries could have a material adverse effect on the Corporation’s business, cost of capital, financial condition and results of operations.

AQN has long-term consolidated corporate credit ratings of BBB from S&P, BBB from DBRS and BBB from Fitch. The ratings indicate the agencies’ assessment of the ability to pay the interest and principal of debt securities issued by the Corporation. See “Description of the Business – Credit Ratings”.

There can be no assurance that any of the current ratings of the Corporation will remain in effect for any given period of time or that a rating will not be lowered or withdrawn entirely by a rating agency if, in its judgment, circumstances in the future so warrant. Factors rating agencies typically consider in evaluating the creditworthiness of a business such as AQN’s include but are not limited to the following: the amount of leverage used in the business, the business mix including the relative contribution to EBITDA (as determined by applicable rating agency methodologies) of regulated utility operations versus non-regulated operations and the countries in which the business operates. Negative changes in these and other factors a rating agency deems to be significant that are expected to be prolonged could result in a credit rating downgrade. Additionally, changes in the capital structure of the Corporation could cause the rating agencies to re-evaluate and potentially downgrade the Corporation’s current credit ratings. A downgrade in credit ratings would result in an increase in the Corporation’s borrowing costs under its bank credit facilities and future long-term debt securities issued. Any such downgrade could also adversely impact the market price of the outstanding securities of the Corporation, could impact the Corporation’s ability to acquire additional regulated utilities and could require the Corporation to post additional collateral security under some of its contracts and hedging arrangements. If any of the Corporation’s ratings fall below investment grade (defined as BBB- or above for S&P and Fitch, BBB (low) or above for DBRS and Baa3 or above for Moody’s), the Corporation’s ability to issue short-term debt or other securities or to market those securities would be constrained or made more difficult or expensive. Therefore, any downgrade could have a material adverse effect on the Corporation’s business, cost of capital, financial condition and results of operations. Each rating agency employs proprietary scoring methodologies that assess business and financial risks of the entity rated. There can be no assurance that the principles on which the rating is based remain consistently applied, and these principles are subject to change from time to time at each rating agency’s discretion. For example, a rating agency’s views on total allowable leverage, specific industry risk factors, country risk and the Corporation’s business mix, among other factors, may change. Such changes could require AQN to adjust its business and strategy in order to maintain its credit ratings. AQN currently anticipates that to continue to maintain a BBB flat investment grade credit rating, it will, among other things, need to execute its growth and asset recycling strategies in a manner that preserves financial leverage targets and continues to generate at least 70% of EBITDA (as determined by applicable rating agency methodologies) from AQN’s Regulated Services Group. There can be no assurance that AQN will be successful, and the failure to do so could have a negative impact on AQN’s credit ratings. The business mix target may from time to time require AQN to grow its Regulated Services Group or implement other strategies in order to pursue investment opportunities within the Renewable Energy Group.

In addition, the Kentucky Power Transaction could also result in a downgrade of the credit rating of Kentucky Power or its outstanding bonds, and could require Kentucky Power to offer to prepay $525 million in principal amount of its outstanding bonds if the credit ratings thereof fall below investment grade (or in the event such bonds are placed on “credit watch” or assigned a “negative outlook” if they are rated BBB- by S&P or Baa3 by Moody’s at such time).

Financial market disruptions or other factors could increase financing costs or limit access to credit and capital markets, which could adversely affect the Corporation’s ability to refinance existing indebtedness on favourable terms, execute its acquisition and investment strategy, and finance its other activities upon favourable terms.

As of December 31, 2022, the Corporation had substantial indebtedness. Management of the Corporation believes, based on its current expectations as to the Corporation’s future performance, that the cash flow from operations, the funds available under its credit facilities and from future asset recycling initiatives, and its ability to access capital markets will be adequate to enable the Corporation to finance its operations, execute its business strategy and maintain an adequate level of liquidity. However, the Corporation’s expected revenue and capital expenditures are only estimates. Moreover, actual cash flows from operations will depend on regulatory, market and other conditions that are beyond the Corporation’s control and which may be impacted by the risk factors herein. As a result, there can be no assurance that management’s expectations as to future performance will be realized.

The Corporation’s ability to obtain additional debt or equity or issue other securities, on favourable terms or at all, may be adversely affected by negative perceptions of the Corporation, any adverse financial or operational performance,

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financial market disruptions, the failure or collapse of any financial institution, prevailing market views and perceptions, or other factors outside the Corporation’s control.

In addition, the Corporation may at times incur indebtedness in excess of its long-term leverage targets, in advance of raising the additional equity capital or similar securities or executing on asset recycling strategies necessary to repay such indebtedness and maintain its long-term leverage target. Any increase in the Corporation’s leverage or degradation of key credit metrics below threshold levels could, among other things: limit the Corporation’s ability to obtain additional financing for working capital, investment in subsidiaries, capital expenditures, debt service requirements, acquisitions and general corporate or other purposes; restrict the Corporation’s flexibility and discretion to operate its business; limit the Corporation’s ability to declare dividends; require the Corporation to dedicate a portion of cash flows from operations to the payment of interest on its existing indebtedness, in which case such cash flows would not be available for other purposes; cause rating agencies to re-evaluate or downgrade the Corporation’s existing credit ratings; require the Corporation to post additional collateral security under some of its contracts and hedging arrangements; expose the Corporation to increased interest expense on borrowings at variable rates; limit the Corporation’s ability to adjust to changing market conditions; place the Corporation at a competitive disadvantage compared to its competitors; make the Corporation vulnerable to any downturn in general economic conditions; render the Corporation unable to make expenditures that are important to its future growth strategies and require the Corporation to pursue alternative funding strategies, which may include accelerated asset recycling initiatives.

The Corporation will need to refinance or reimburse amounts outstanding under the Corporation’s existing consolidated indebtedness over time. There can be no assurance that the Corporation will be successful in refinancing its indebtedness when necessary or that additional financing will be obtained when needed, on commercially reasonable terms or at all. In the event that the Corporation cannot refinance indebtedness or raise additional indebtedness, or if the Corporation cannot refinance its indebtedness or raise additional indebtedness on terms that are not less favourable than the current terms, the Corporation’s cash flows, ability to declare dividends or repay its indebtedness may be adversely affected.

The Corporation’s ability to meet its debt service requirements will depend on its ability to generate cash in the future, which depends on many factors, including the Corporation’s financial performance, debt service obligations, the realization of the anticipated benefits of acquisition and investment activities, and working capital and capital expenditure requirements. In addition, the Corporation’s ability to borrow funds in the future to make payments on outstanding debt will depend on the satisfaction of covenants in existing credit agreements and other agreements. A failure to comply with any covenants or obligations under the Corporation’s consolidated indebtedness could result in a default under one or more such instruments, which, if not cured or waived, could result in the termination of dividends by the Corporation and permit acceleration of the relevant indebtedness. There can be no assurance that, if such indebtedness were to be accelerated, the Corporation’s assets would be sufficient to repay such indebtedness in full. There can also be no assurance that the Corporation will generate cash flow in amounts sufficient to pay its outstanding indebtedness or to fund the Corporation’s liquidity needs.

Fluctuations in interest rates could negatively affect the Corporation’s financing costs, ability to access capital and ability to continue successfully implementing its business strategy.

The Corporation is exposed to interest rate risk from certain outstanding variable interest indebtedness and any new credit facilities and debt issuances. Fluctuations in interest rates may also impact the costs to obtain other forms of capital. In addition, for the Regulated Services Group, costs resulting from interest rate increases may not be recoverable in whole or in part, and “regulatory lag” may cause a time delay in the payment to the Regulated Services Group of any such costs that are recoverable. Rising interest rates may also negatively impact the economics of development projects, acquisitions and energy facilities, especially where project financing is being renewed or arranged. As a result, fluctuations in interest rates could materially increase the Corporation’s financing costs, limit the Corporation’s options for financing, and adversely affect its results of operations, cash flows, key credit metrics, borrowing capacity and ability to implement its business strategy.

Certain of AQN and its subsidiaries’ loans, debt securities and derivative contracts use the London Inter-Bank Offered Rate and CDOR as benchmarks for establishing the interest rate, each of which will be replaced with a different reference rate. Any replacement benchmark may not be the economic equivalent of the London Inter-Bank Offered Rate or CDOR, as applicable. The discontinuation and replacement of London Inter-Bank Offered Rate and CDOR may, among other things, increase the Corporation’s cost of borrowing, may have an unpredictable impact on credit and financial markets and could negatively impact the Corporation’s financial condition.

Currency exchange rate fluctuations may affect the Corporation’s financial results and increase certain financing risks.

The functional currency of most of the Corporation’s operations and development activities is the U.S. dollar. However, the Corporation is exposed to currency fluctuations from its Canadian and Chilean operations and may utilize equipment and/or commodities purchased from foreign suppliers. Although the Corporation may hedge currency exchange rate exposure, the Corporation typically does not hedge its full exposure. If the Corporation does enter into currency hedges and exchange rates move in a favourable direction, such currency hedges may reduce or eliminate the Corporation’s realization of the benefit of favourable exchange rate movement. In addition, currency hedging transactions will be subject to risks that the applicable counterparty may prove unable or unwilling to perform its obligations under the contract, as a result of which the Corporation would lose some or all of the anticipated benefits of such hedging transactions.

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The Corporation is, and will continue to be, party to agreements, including credit agreements and indentures, that contain covenants that restrict its financial flexibility.

The Corporation’s existing credit facilities contain covenants imposing certain requirements on the Corporation’s business including covenants regarding the ratio of indebtedness to total capitalization. Furthermore, AQN and its subsidiaries have, and may continue to, periodically issue long-term debt, which may consist of both secured and unsecured indebtedness. These third-party debt agreements also contain covenants, including covenants regarding the ratio of indebtedness to total capitalization. These requirements may limit the Corporation’s ability to take advantage of potential business opportunities as they arise and may adversely affect the Corporation’s conduct and the current business of certain operating subsidiaries, including restricting the ability to finance future operations and capital needs and limiting the subsidiaries’ ability to engage in other business activities. Other covenants place or could place restrictions on the Corporation’s ability and the ability of its subsidiaries to, among other things, incur additional debt, create liens, and sell or transfer assets.

Agreements the Corporation enters into in the future may also have similar or more restrictive covenants, especially if the general credit market deteriorates. A breach of any covenant in the existing credit facilities or the agreements governing the Corporation’s other indebtedness would result in an event of default. Certain events of default may trigger automatic acceleration of payment of the underlying obligations or may trigger acceleration of payment if not remedied within a specified period. Events of default under one agreement may trigger events of default under other agreements. Should payments become accelerated as the result of an event of default, the principal and interest on such borrowing would become due and payable immediately. If that should occur, the Corporation may not be able to make all of the required payments or borrow sufficient funds to refinance the accelerated debt obligations. Even if new financing is then available, it may not be on terms that are acceptable to the Corporation.

A significant portion of the Corporation’s debt will mature over the next five years and will need to be paid or refinanced, and changes to the debt and equity markets could adversely affect the Corporation’s business.

A significant portion of the Corporation’s debt is set to mature in the next five years, including its revolving credit facility. The Corporation may not be able to refinance its maturing debt on commercially reasonable terms, or at all, depending on numerous factors, including its financial condition and prospects at the time and the then current state of the banking and capital markets in Canada and the United States.

Challenges to the Corporation’s tax positions, and changes in applicable tax laws, could materially and adversely affect returns to the Corporation’s shareholders.

The Corporation is subject to income and other taxes primarily in the United States and Canada; however, it is also subject to income and other taxes in international jurisdictions, such as Chile and Bermuda. Changes in tax laws or interpretations thereof in the jurisdictions in which the Corporation does business could adversely affect the Corporation’s results from operations, returns to shareholders, and cash flows. One or more taxing jurisdictions could seek to impose incremental or new taxes on the Corporation pursuant to one of the following or otherwise:

•The Inflation Reduction Act was signed into law in the United States on August 16, 2022. The legislation is inclusive of an extension and expansion of clean energy tax credits and a minimum tax. The minimum tax is not expected to be applicable to the Corporation in the near term; however, the Corporation cannot provide any assurance that it will not apply in the longer term.

•On April 19, 2021, the Canadian federal government delivered its 2021 budget which contained proposed measures related to limitations on interest deductibility and changes in relation to international taxation. Draft legislative proposals pertaining to interest deductibility were initially released for public comment on February 4, 2022, with revised legislative proposals subsequently released on November 3, 2022. The proposed rules on interest deductibility are expected to be effective no earlier than January 1, 2024. The proposed rules and their application are complex and could have a material adverse impact on the Corporation's effective tax rate and financial results in future years if enacted as drafted.

•As a consequence of the Organization for Economic Co-operation and Development’s (“OECD”) various initiatives on “Base Erosion and Profit Shifting”, there has been increased focus by taxing authorities across the globe to pursue common international principles for the entitlement to taxation of global corporate profits and eliminate perceived tax advantages enjoyed by multinational enterprises. Certain components of the relevant legislation in the jurisdictions in which the Corporation operates or has domiciled subsidiaries are expected to apply with application expected no earlier than January 1, 2023. As the local legislation in the various jurisdictions is enacted and comes into effect, there is a risk that the Corporation’s tax expense and/or cash taxes could materially increase or that the Corporation’s interpretation of the new legislation may not align with that of the relevant tax authority’s interpretation. This could have a material adverse effect on the Corporation’s financial condition, results of operations, and cash flows in future periods.

The Corporation cannot provide assurance that the Canada Revenue Agency, the Internal Revenue Service or any other applicable taxation authority will agree with the tax positions taken by the Corporation, including with respect to claimed expenses and the cost amount of the Corporation’s depreciable properties. A successful challenge by an applicable taxation authority regarding such tax positions could adversely affect the results of operations and financial position of the Corporation.

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Development by the Corporation of renewable power generation facilities in the United States depends in part on federal tax credits and other tax incentives. The Inflation Reduction Act has extended and expanded certain energy credits, providing greater certainty regarding the availability of these credits on a going forward basis. However, the rules governing these tax credits still include technical requirements for credit eligibility. If the Corporation is unable to complete construction on current or planned projects within certain deadlines or satisfy certain new requirements relating to prevailing wage and apprenticeship requirements, the reduced incentives may be insufficient to support continued development or may result in substantially reduced financial benefits from facilities or long-term investment in facilities that the Corporation is committed to complete. In addition, the Corporation has entered into certain tax equity financing transactions with financial partners for certain of its renewable power facilities in the United States, under which allocations of future cash flows to the Corporation from the applicable facility could be adversely affected in the event that there are changes in U.S. tax laws that apply to facilities previously placed in service.

The Corporation is subject to funding risks associated with defined benefit pension and OPEB plans.

Certain utility businesses acquired by the Corporation maintain traditional defined benefit pension plans covering eligible employees and retirees, and other post-employment benefit (“OPEB”) plans for eligible retired employees, including retiree health care and life insurance benefits. The Regulated Services Group and the Renewable Energy Group also provide a cash balance pension plan covering all of their U.S. employees who are not eligible for a traditional pension plan or who are not otherwise covered by a legacy plan, under which employees are credited with a percentage of base pay plus a prescribed interest rate credit.

Future contributions to the Corporation’s plans are impacted by a number of variables, including the investment performance of the plans’ assets, interest rates used to discount future benefits, changes in actuarial assumptions, regulations or life expectancy and the frequency and amount of the Corporation’s contributions made to the plans. If capital market returns are below assumed levels, or if the interest rates used to discount future benefits decrease, the Corporation could be required to make contributions to its plans in excess of those currently expected, which would adversely affect the Corporation’s cash flows.

The Corporation is subject to credit risk of customers and other counterparties.

The Corporation is subject to credit risk with respect to the ability of customers and other counterparties to perform their obligations to the Corporation, including paying amounts that they owe to the Corporation. This credit risk exists with respect to utility customers, banks and other financing sources, as well as counterparties to Offtake Contracts, supply agreements, EPC contracts, and derivative financial instruments, among others. Additionally, bank deposits in excess of deposit insurance limits are subject to the risk that such excess amounts could be lost or forfeited in the event of a bank failure.

Adverse conditions in the energy industry or in the general economy, including the effects of the COVID-19 pandemic, as well as circumstances of individual customers or counterparties, may adversely affect the ability of a customer or counterparty to perform as required under its contract with the Corporation. Losses from a utility customer may not be offset by bad debt reserves approved by the applicable utility regulator. If a customer under an Offtake Contract is unable to perform, the Renewable Energy Group may be unable to replace the contract on comparable terms, in which case sales of power (and, if applicable, RECs and ancillary services) from the facility would be subject to market price risk and may require refinancing of indebtedness related to the facility or otherwise have a material adverse effect. Default by other counterparties, including lenders and counterparties to supply and construction contracts, hedging contracts that are in an asset position, short-term investments, agreements for the purchase of goods or services or other agreements, also could adversely affect the financial results of the Corporation.

The Corporation makes certain assumptions, judgments and estimates that affect amounts reported in its consolidated financial statements, which, if not accurate, may adversely affect its financial results.

AQN prepares its consolidated financial statements in accordance with U.S. GAAP. The preparation of consolidated financial statements requires management to make estimates and assumptions that affect the reported amounts of assets and liabilities, related amounts of revenues and expenses, and disclosure of contingent assets and liabilities. Significant areas requiring the use of management judgment include the scope of consolidated entities, useful lives and recoverability of depreciable assets, the measurement of deferred taxes and the recoverability of deferred tax assets, rate-regulation, unbilled revenue, asset retirement obligations, pension and post-employment benefits, fair value of derivatives and fair value of assets and liabilities acquired in a business combination. Actual results may differ from these estimates and any inaccuracies in these estimates could result in the Corporation incurring significant expenses and adversely affect the Corporation’s financial results.

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As a foreign private issuer, AQN is subject to different U.S. securities laws and rules than a domestic U.S. issuer, which may limit the information publicly available to shareholders.

AQN is a “foreign private issuer,” as such term is defined in Rule 405 under the U.S. Securities Act of 1933, as amended, and is permitted, under a multijurisdictional disclosure system adopted by the U.S. and Canada, to prepare its disclosure documents under the U.S. Securities Exchange Act of 1934, as amended (the “U.S. Exchange Act”) in accordance with Canadian disclosure requirements. Under the U.S. Exchange Act, AQN is subject to reporting obligations that, in certain respects, are less detailed and less frequent than those of U.S. domestic reporting companies. As a result, AQN does not file the same reports that a U.S. domestic issuer would file with the SEC, although AQN is required to file or furnish to the SEC the continuous disclosure documents that it is required to file in Canada under Canadian securities laws. In addition, AQN’s officers, directors, and principal shareholders are exempt from the reporting and “short swing” profit recovery provisions of Section 16 of the U.S. Exchange Act. Therefore, AQN’s shareholders may not know on as timely a basis when AQN’s officers, directors and principal shareholders purchase or sell shares, as the reporting deadlines under the corresponding Canadian insider reporting requirements are longer.

As a foreign private issuer, AQN is exempt from the rules and regulations under the U.S. Exchange Act related to the furnishing and content of proxy statements. AQN is also exempt from Regulation FD, which prohibits issuers from making selective disclosures of material non-public information. While AQN is required to comply with the corresponding requirements relating to proxy statements and disclosure of material non-public information under Canadian securities laws, these requirements differ from those under the U.S. Exchange Act and Regulation FD and shareholders should not expect to receive the same information at the same time as such information is provided by U.S. domestic companies. In addition, AQN has four months after the end of each fiscal year to file its annual information form with the SEC and is not required under the U.S. Exchange Act to file quarterly reports with the SEC as promptly as U.S. domestic companies whose securities are registered under the U.S. Exchange Act.

In addition, as a foreign private issuer, AQN has the option to follow certain Canadian corporate governance practices, except to the extent that such laws would be contrary to U.S. securities laws, and provided that AQN discloses the requirements that it is not following and describe the Canadian practices it follows instead. AQN currently relies on this exemption with respect to requirements regarding the quorum for any meeting of its shareholders. AQN may in the future elect to follow home country practices in Canada with regard to other matters. As a result, AQN’s shareholders may not have the same protections afforded to shareholders of U.S. domestic companies that are subject to all U.S. corporate governance requirements.

4.3Risk Factors Relating to Regulatory Environment

The Corporation’s business, financial condition, results of operations and prospects depends in part on regulatory climates and regulatory outcomes in the jurisdictions in which it operates, and the failure to recover in a timely manner any significant amount of costs or obtain expected returns on assets or invested capital through rate base, cost recovery clauses, and other regulatory mechanisms or otherwise maintain required regulatory authorizations could materially and adversely affect the Corporation.

The Corporation is subject to comprehensive laws, regulations, orders and other requirements of a variety of federal, provincial, state, and local governments, including regulatory commissions, environmental agencies and other regulatory bodies, which laws, regulations, orders and other requirements affect the operations and activities of, and costs incurred by, the Corporation. This extensive regulatory framework regulates, among other things and to varying degrees, the Corporation’s industry, businesses, rates and cost structures, operation and licensing of generation facilities, management, financing, planning, growth, construction and operation of generation, transmission and distribution facilities, acquisition, disposal, depreciation and amortization of facilities and other assets, decommissioning costs and funding, service reliability, wholesale and retail competition, commodities trading, derivatives transactions, financing, employees, and environmental, health and safety standards. Such laws and regulations impose significant and increasing compliance costs on the Corporation’s operations. If any of the Corporation’s business units is found to be in violation of applicable requirements or regulations, it could be subject to significant penalties and reputational risk. Changes in rules or regulations or the imposition of additional rules or regulations also could have a material adverse effect on the Corporation’s business, prospects, financial condition and results of operations.

The utility commissions in the jurisdictions in which the Regulated Services Group operates regulate many aspects of its utility operations, including the rates that the Regulated Services Group can charge customers, issuance of securities or other financing instruments and debt obligations, siting and construction of facilities, pipeline safety and compliance, customer service and the utility’s ability to recover the costs that it incurs, including capital expenditures and fuel and purchased power costs. Changes in rate-setting models and methodologies may have a material adverse impact on the Corporation’s revenue and net income.

A fundamental risk faced by a regulated utility is the disallowance by the utility’s regulator of operating expenses or capital costs requested to be placed into the utility’s revenue requirement. In addition, capital investments that have become stranded may pose additional risk for cost recovery and could be subject to legislation or rulings that would impact the extent to which such costs could be recovered. Similarly, recovery of extraordinary fuel expenses may pose additional risk for cost recovery and could be subject to legislation that would impact the extent to which such costs could be recovered. In addition, the time between the incurrence of costs and the granting of the rates to recover those costs by such regulatory agencies – known as “regulatory lag” – can adversely affect profitability. If the Corporation is

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unable to recover increased costs of operations or its investments in new facilities, or in the event of significant regulatory lag, the Corporation’s results of operations could be adversely affected.

In addition, there is a risk that the utility’s regulator will not approve the revenue requirements requested in outstanding or future applications for rates or will, on its own initiative, seek to reduce the existing revenue requirements. Rate applications for revenue requirements are subject to the utility regulator’s review process, usually involving participation from intervenors and a public hearing process. There can be no assurance that resulting decisions or rate orders issued by the utility regulators will permit the Corporation to recover all costs actually incurred, costs of debt and income taxes, or to earn a particular return on equity. A failure to obtain acceptable rate orders, or approvals of appropriate returns on equity and costs actually incurred, may materially adversely affect: the Regulated Services Group’s businesses, the undertaking or timing of capital expenditures, ratings assigned by credit rating agencies, the cost and issuance of debt, and other matters, any of which may in turn have a material adverse effect on the Corporation. In some instances, denial of recovery may cause the regulated subsidiaries to record an impairment of assets. In addition, there is no assurance that the Corporation will receive regulatory decisions in a timely manner and, therefore, there may be a significant lag in the timing of cost recovery relative to the time in which costs are incurred.

In the case of some of the Corporation’s hydroelectric generating facilities, water rights are owned by governments that reserve the right to control water levels, which may affect revenue, while in the United States, hydroelectric generating facilities are required to be licensed or have valid exemptions from FERC. The failure to obtain all necessary licenses or permits for such facilities, including renewals thereof or modifications thereto, may result in an inability to operate the facility and could adversely affect cash generated from operating activities.

FERC has jurisdiction over wholesale rates for all electric energy sold by the Renewable Energy Group and the Regulated Services Group in the United States. Certain of the Renewable Energy Group’s facilities in the United States are required to meet the requirements of a “qualifying facility” or an “exempt wholesale generator” and, subject to certain exceptions, to obtain and maintain authority from FERC to sell power at market-based rates. The failure of the Renewable Energy Group or the Regulated Services Group to obtain or maintain, as applicable, market-based rate authorization for its facilities and to comply with market rules, regulations and other applicable legal requirements could materially and adversely affect the Corporation.

Additionally, owners, operators and users of the bulk electric system in the United States are subject to mandatory reliability standards developed by the NERC and its regional entities. Reliability standards have also been implemented in the Canadian provinces in which the Corporation has assets. In Bermuda, the RAB regulates the reliability standards related to electricity transmission, distribution, and retail services and bulk electric generation. Increased reliability standard compliance obligations may cause higher operating costs or capital expenditures for the Corporation's utilities. If the Corporation were found to be in non-compliance with the mandatory reliability standards, the Corporation could be subject to sanctions, including substantial monetary penalties.

The Corporation is subject to numerous environmental, health and safety laws, regulations and other standards and faces a number of environmental risks which have the potential to result in significant environmental liabilities, civil or criminal penalties, increases capital expenditures, reputational impacts or in mitigation or cessation of certain operations or projects, and could have a material adverse effect on the Corporation’s business, financial condition, results of operation and cash flows.

The Corporation is subject to extensive federal, state, provincial and local regulation with regard to water quality, hazardous and solid waste management, the storage, handling, use and transportation of dangerous goods and hazardous and residual materials, wastewater discharges, air quality control, air emissions, soil quality, discharge of pollutants, environmental remediation, historical artifact preservation, wildlife, health and other environmental matters. The Corporation is also subject to extensive laws and regulations relating to work and public health and safety matters. Failure to comply with these laws and regulations could have a material adverse effect on the Corporation’s results of operations and financial position. In addition, new environmental, health or safety laws and regulations, and new interpretations of existing environmental, health or safety laws and regulations, have been adopted and may in the future be adopted, which may substantially increase the Corporation’s future expenditures and compliance costs, and could cause the Corporation to retire generating capacity prior to the end of its estimated useful life.

AQN and its subsidiaries face a number of environmental risks, which have the potential to result in harm to the environment, including wildlife, and significant environmental liabilities and reputational impact. Certain environmental risks associated with the Corporation’s operations include uncontrolled natural gas or contaminant releases (or releases above the permitted limits), water contamination above permitted levels, generation of hazardous wastes, failure to maintain compliance with obligations under laws, rules, regulations, permits and licenses, acquired legacy environmental liabilities, operations adjustments or liability, and related financial impacts. In certain circumstances, the Corporation may be responsible for the remediation of contamination, even if such contamination was caused by a third party. Remediation costs incurred by the Corporation as a result of the foregoing events may be significant and may not be recoverable.

In addition, the Corporation’s operating subsidiaries generate certain wastes, some of which are characterized as hazardous, which must be managed in accordance with various federal, state, provincial and local environmental laws. Under federal, provincial and state laws, liability for historic contamination of property may be imposed on potentially responsible parties jointly and severally, without fault, even if the activities were lawful when they occurred.

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Power generation, transmission and distribution operations can adversely affect endangered, threatened or otherwise protected species under federal, state or provincial statutes, laws, rules and regulations. Operation of wind projects and transmission and distribution lines involve a risk that protected flying species, such as birds and bats, may be impacted, and such impacts can be fatal. Violations of wildlife protection laws in certain jurisdictions, including violations of certain laws protecting migratory birds and endangered species, may result in civil or criminal penalties, mitigation or cessation of certain operations or projects, and could adversely affect the Corporation’s financial condition, results of operations and cash flows.

Although a portion of the Corporation’s electricity generation is produced by the combustion of fossil fuels, all of the electricity generated by Kentucky Power is produced by the combustion of fossil fuels. As a result, the acquisition of Kentucky Power would increase the overall percentage of the Corporation’s electricity generation that is produced by the combustion of fossil fuels and could result in reputational harm to the Corporation and adversely affect perceptions regarding the Corporation’s commitment to environmental and sustainability matters, as well as the Corporation’s ability to accomplish its environmental and sustainability objectives. The operation of fossil-fueled generation plants, including resulting emissions of nitrogen and sulfur oxides, mercury and particulates and the discharge and disposal of solid waste (including coal combustion residuals (“CCRs”)), is subject to extensive federal, state and local environmental statutes, rules and regulations relating to air quality, water quality, waste management, natural resources and health and safety. Compliance with these requirements requires Kentucky Power to incur significant costs, including capital expenditures, for environmental monitoring, installation of pollution control equipment, emission fees, disposal activities, decommissioning, and permitting obligations. If these compliance costs become uneconomical Kentucky Power may ultimately be required to retire generating capacity prior to the end of its estimated life. The costs of complying with these legal requirements could also adversely affect Kentucky Power’s results of operations, financial condition and cash flows, and those of the Corporation following the closing of the Kentucky Power Transaction. In addition, the impacts could become even more significant if existing requirements governing air emissions management and disposal, CCR waste and/or waste matter discharge become more restrictive in the future, more extensive operating and/or permitting requirements are imposed or additional substances associated with power generation are subjected to increased regulation. Although Kentucky Power typically recovers expenditures for pollution control technologies, replacement generation, undepreciated plant balances and associated operating costs from customers, there can be no assurance that Kentucky Power will be able to obtain a rate order to fully recover the remaining costs associated with such plants in the future. The failure to recover these costs could reduce Kentucky Power’s results of operations, financial condition and cash flows, and those of the Corporation following the closing of the Kentucky Power Transaction.

In addition, future changes to environmental laws, including with respect to the regulation of CO2 emissions, could cause the Corporation and Kentucky Power to incur materially higher costs than Kentucky Power has incurred to date.

The Regulated Services Group’s electricity, water, wastewater and natural gas distribution systems could be subject to condemnation or other methods of taking by government entities under certain conditions (including, without limitation, Liberty Utilities (Apple Valley Ranchos Water) Corp., which has been the subject of a condemnation lawsuit filed by the Town of Apple Valley and Liberty New York Water, which has received condemnation inquiries). There can be no assurance that any value will be received for such assets by the Corporation and may result in a loss to the Corporation.

The Corporation is subject to risks related to changes in laws and regulations, and other actions by governmental and regulatory authorities, that could adversely affect the Corporation’s business, regulatory approvals, assets, results of operations and financial condition.

The operations and activities of AQN, its subsidiaries and its business units are subject to the laws, regulations, orders and other requirements of a variety of federal, state, provincial and local governments, including regulatory commissions, environmental agencies and other regulatory bodies, which laws, regulations, orders and other requirements affect the operations and activities of, and costs incurred by, the Corporation. The Corporation is accordingly subject to: risks associated with changing political conditions and changes in, modifications to, or reinterpretations of, existing laws, orders or regulations, the imposition of new laws, orders or regulations (including those adopted in the State of New York allowing the North Shore Water Authority and the South Nassau Water Authority to operate in the territories of private water companies, including the power of eminent domain, and possible changes to the constitution of Chile, such as changes to the water rights rules and to provisions governing ownership of water and wastewater utilities), and the taking of other action by governmental or regulatory authorities, including, but not limited to, revocation, lapse, limitation or non-renewal of utility franchises or other rights to provide utility services to existing or new customers, potential limitations on water rights used by utilities in providing service, actions to municipalize utility service areas or limitations on utility growth and/or expansions of service areas, any of which could adversely affect the Corporation’s business, regulatory approvals, assets, results of operations and financial condition. If the Corporation or any of its subsidiaries or business units were found to be in violation of such applicable laws, regulations, orders or other requirements, they could be subject to significant penalties or legal actions.

The Corporation operates in markets, and may in the future pursue growth opportunities in new markets, that are subject to foreign laws and regulations that are more onerous or uncertain than the laws and regulations of the United States or Canada.

The Corporation operates in markets, or may pursue growth opportunities in new markets, that are subject to regulation by various foreign governments and regulatory authorities and to the application of foreign laws. Such foreign laws or

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regulations may not provide the same type of legal certainty and rights, in connection with the Corporation’s contractual relationships in such countries, as are afforded to the Corporation in Canada and the U.S., which may adversely affect the Corporation’s ability to receive revenues or enforce its rights in connection with any operations or projects in such jurisdictions. In addition, the laws and regulations of some countries may limit the Corporation’s ability to hold a majority interest in certain projects, thus limiting the Corporation’s ability to control the operations of such projects. Any existing or new operations or interests of the Corporation may also be subject to significant political, economic and financial risks, which vary by country, and may include: (i) changes in government laws, policies or personnel or a country’s constitution; (ii) changes in general economic conditions; (iii) restrictions on currency transfer or convertibility; (iv) changes in labour relations; (v) political instability and civil unrest; (vi) regulatory or other changes adversely affecting the local utility market; (vii) breach or repudiation of important contractual undertakings and expropriation and confiscation of assets and facilities without compensation or compensation that is less than fair market value; (viii) less developed or efficient financial markets than in North America; (ix) the absence of uniform accounting, auditing and financial reporting standards, practices and disclosure requirements; (x) less government supervision and regulation; (xi) a less developed legal or regulatory environment, including uncertainty in outcomes and actions that may be inconsistent with the rule of law; (xii) heightened exposure to corruption risk; (xiii) political hostility to investments by foreign investors, including laws affecting foreign ownership; (xiv) less publicly available information in respect of companies; (xv) adversely higher or lower rates of inflation; (xvi) higher transaction costs; and (xvii) fewer investor protections.

Tariffs imposed on imported goods and import restrictions imposed by governmental authorities may increase the capital cost of projects and have a negative impact on the Corporation’s expected returns, results of operations and cash flows.

Changes in tariffs may adversely affect the capital expenditures required to develop or construct the Corporation’s projects. In the U.S., tariffs have been imposed in recent years to imports of solar panels, aluminum and steel, among other goods and raw materials. Trade disputes may result in additional tariffs or changes in existing ones. In addition, import restrictions, border delays and seizures of products by governmental authorities may increase the cost of projects and result in construction and placed-in-service delays. These occurrences may have adverse impacts to the Corporation, as the buyer of goods, which could adversely affect the Corporation’s expected returns, results of operations and cash flows.

The Corporation may suffer a significant loss resulting from fraud, bribery, corruption, other illegal acts, inadequate or failed internal processes or systems.

The Corporation may suffer a significant loss resulting from fraud, bribery, corruption or other illegal acts, or from inadequate or failed internal processes or systems. The Corporation operates in multiple jurisdictions and it is possible that its operations and development activities may expand into new jurisdictions. Doing business in multiple jurisdictions requires the Corporation to comply with the laws and regulations of such jurisdictions. These laws and regulations may apply to the Corporation, its subsidiaries, individual directors, officers, employees and third-party agents. The Corporation is also subject to anti-bribery and anti-corruption laws, including the Canadian Corruption of Foreign Public Officials Act and the U.S. Foreign Corrupt Practices Act. As the Corporation makes acquisitions and pursues development activities internationally, it is exposed to increased corruption-related risks, including potential violations of applicable anti-corruption laws.

The Corporation relies on its infrastructure, controls, systems and personnel, as well as central groups focusing on enterprise-wide management of specific operational risks such as fraud, trading, outsourcing, and business disruption, to manage the risk of illegal and corrupt acts or failed systems. The Corporation also relies on its employees and certain third parties to comply with its policies and processes as well as applicable laws. The failure to adequately identify or manage these risks, and the acquisition of businesses with weak internal controls to manage the risk of illegal or corrupt acts, could result in direct or indirect financial loss, regulatory censure and/or harm to the Corporation’s reputation.

4.4Risk Factors Relating to Strategic Planning and Execution

The Corporation is subject to risks associated with its growth strategy that may adversely affect its business, results of operations, financial condition and cash flows, and actual capital expenditures may be lower than planned.

The Corporation has a history of growth through acquisitions and organic growth from development projects and capital expenditures. There is no certainty that the Corporation will be successful in pursuing its growth strategy in the future. There can be no assurance that the Corporation will be able to identify attractive acquisition or development candidates in the future or that it will be able to realize growth opportunities that improve the Corporation’s financial results or increase the amount of cash available for distribution. There is also a risk that errors and/or inaccurate assumptions in AQN’s financial models could impact its growth.

The Corporation’s growth strategy may be constrained by factors associated with the maintenance of its BBB flat investment grade credit rating. These factors include: (i) constraints on maximum leverage, (ii) the proportion of EBITDA (as determined by applicable rating agency methodologies) required to be generated from the Regulated Services Group, and (iii) the geographies in which AQN can operate in scale. There can be no assurance that these constraints will not negatively impact the Corporation’s ability to successfully execute on available growth opportunities. The Corporation

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may also face significant competition for growth opportunities and, to the extent that any opportunities are identified, may be unable to effect such growth opportunities due to a lack of necessary or cost competitive capital resources. Risks related to capital projects include schedule delays and project cost overruns. There is no assurance that any project cost overruns would be approved for recovery in customer rates.

Any growth opportunity could involve potential risks, including an increase in indebtedness, the potential disruption to the Corporation’s ongoing business, the diversion of management’s attention from other business concerns and the possibility that the Corporation will incur more costs than originally anticipated or, in the case of acquisitions, more than the acquired company or interest is worth. In addition, funding requirements associated with the growth opportunity, including any acquisition, development or integration costs, may reduce the funds available to pay dividends.

The Regulated Services Group’s capital expenditure program and associated rate base growth are key assumptions in the Corporation’s targeted dividend growth. Actual capital expenditures may be lower than planned due to factors beyond the Corporation’s control, which would result in a lower than anticipated rate base and have an adverse effect on the Corporation’s results of operations, financial condition, cash flows and dividend growth.

The Corporation’s development and construction activities are subject to material risks, including expenditures for projects that may prove not to be viable, construction cost overruns and delays, inaccurate estimates of expected energy output or other factors, and failure to satisfy tax incentive requirements or to meet third-party financing requirements.

The Corporation actively engages in the development and construction of new power generation facilities, and currently has a pipeline of renewable energy projects in development or construction, as well as the development and construction of transmission and distribution assets and other complementary projects. In addition, each of the Corporation’s business segments may occasionally undertake construction activities as part of normal course maintenance activities.

Significant costs must be incurred to determine the technical feasibility of a project, obtain necessary regulatory approvals and permits, obtain system studies and access, conduct environmental assessments, obtain site control and interconnection rights and negotiate revenue, construction and equipment supply contracts for the facility before the viability of the project can be determined. Regulatory approvals can be challenged through a number of mechanisms which vary across state and provincial jurisdictions. Such challenges could identify issues that may result in permits or approvals being modified or revoked, or the failure of a project to proceed and the resultant loss of amounts invested or expenses already incurred. Additionally, the Corporation may also be required to advance funds, enter into commitments and/or post performance bonds, parental guarantees, letters of credit or other security in the course of acquiring, developing, constructing and financing new power generation facilities. Significant costs related to prospective development projects may be incurred in preparation for any associated bidding process and such costs may not be recovered if the Corporation fails to win the bid. With its expanded greenfield development pipeline, the Corporation is increasingly pursuing earlier-stage development prospects which are inherently riskier than late-stage developments. Projects may fail to reach financial close, and all investments, cost commitments and credit support provided up to that point, which could be material, may be lost or unrealizable.

Material delays, cost overruns and lost revenue could be incurred by the Corporation and its development and construction projects as a result of vendor or contractor non-performance, technical issues with interconnection and the interconnection utility, required upgrades to interconnection facilities, required curtailments of generation, delays in obtaining interconnection rights, disputes with landowners or other parties, severe weather, increased inflation, interest rates, commodity price trends, issues with results of system studies, supply chain issues, and other causes. In addition, there are risks that actual costs may exceed budget estimates, delays may occur in obtaining permits and materials, suppliers and contractors may not perform as required under their contracts, warranties under contracts may be unfilled or insufficient, there may be inadequate availability, productivity or increased cost of qualified craft or local labour, start-up activities may take longer than planned, curtailment of a facility’s output may be required, the scope, actual or expected returns, and timing of projects may change, and other events beyond the Corporation’s control may occur, in each case that may materially affect the viability, schedule, budget, cost and performance of projects.

The Corporation’s assessment of the viability, revenues and profitability of a renewable facility depends upon estimates regarding the availability, strength and consistency of the applicable resource (such as wind, solar radiance, RNG or hydrology) and other factors, such as assessments of the facility’s potential impact on wildlife. If weather patterns change, unanticipated or one-off events occur or actual data proves to be materially different than estimates, the generation from the facility and resulting revenues and profitability may differ significantly from expected amounts.

For certain of its development projects, the Corporation relies on financing from third party tax equity investors, the participation of which depends upon qualification of the project for U.S. tax incentives and satisfaction of the investors’ investment criteria. These investors typically provide funding upon commercial operation of the facility. Should certain facilities not meet the conditions required for tax equity funding, expected returns from the facilities may be adversely impacted.

The Corporation’s construction activities relating to its utility and power generation projects utilize a variety of products and materials. The cost to the Corporation of such products and materials may be impacted by a number of factors beyond the Corporation’s control, including their general availability, inflationary and commodity price trends, the impact of tariffs, duties and import restrictions imposed by various governmental authorities and the existence of any global or regional political, health or economic crisis. While the Regulated Services Group may be able to recover any

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such increased costs in future rate cases, there is generally no such recovery mechanism available to the Renewable Energy Group for such costs. The financial condition and results of operations of the Corporation may be impacted as a result.

Energy generated by the Corporation is often sold under PPAs, unit contingent or fixed-shape offtake contracts or other energy offtake or hedging arrangements (together with PPAs, “Offtake Contracts”). These Offtake Contracts generally contain customary terms including: the amount paid for energy from the project over the term of the agreement (which rate can be materially higher or lower than prevailing market rates) and a requirement for the project to comply with technical standards and to achieve commercial operation within time frames prescribed by the contract. A failure to achieve satisfactory construction progress and/or the occurrence of any permitting or other unanticipated delays at a project could result in a failure to comply with the applicable contract’s requirements within the specified time frames. In addition, once an Offtake Contract is entered into, there is a risk that increases in project costs following the entering into of such Offtake Contract, such as increases in interest rates, inflation, costs of materials, contractor costs and other construction costs, may negatively impact project economics or viability. Further, there is a risk that the Corporation is not able to generate the specified amount of power at the specified time resulting in production shortfalls under an Offtake Contract that then requires the Corporation to purchase power in the merchant market under prevailing rates. Any event that restricts production increases shortfall risk. Events that can reduce production include (but are not limited to) weather events (such as icing, low wind resource, cloud cover), transmission outages and mechanical failure. Offtake Contracts may also cause the Corporation to incur basis risk, being the difference between the pricing at the location where power is delivered and where the Offtake Agreement settles, which may result in reduced net revenue and earnings volatility for the Corporation. Remedies for failure to comply with material provisions of an Offtake Contracts generally include, among other things, the potential termination of the agreement by the non-defaulting party. Any such termination could have a material adverse effect on the Corporation’s results of operations and financial position.

Public opposition to larger infrastructure projects and renewable energy projects in certain areas is common, which may impact the Corporation’s capital programs, development activities and operations. The social acceptance by external stakeholders, including, in some cases, First Nations and other indigenous peoples, local communities, landowners and other interest groups, may be critical to the Corporation’s ability to find and develop new sites suitable for viable renewable energy projects. Failure to obtain proper social acceptance for a project may prevent the development and construction of a project and lead to the loss of all investments made in the development and the write-off of such prospective project. Failure to effectively respond to public opposition may adversely affect the Corporation’s capital expenditure programs, and, therefore, future organic growth, which could adversely affect its results of operations, financial condition and cash flows.

The Renewable Energy Group depends on certain key customers for a significant portion of its revenues. The loss of a key customer or the failure to secure new Offtake Contracts or renew existing Offtake Contracts could increase market price risk with respect to the sale of generated energy and renewable energy credits.

A substantial portion of the output of the Renewable Energy Group’s power generation facilities is sold under long-term Offtake Contracts, under which a purchaser is obligated to purchase all or a specified portion of the output of the applicable facility and (in many cases) associated RECs. The termination or expiry of any such Offtake Contract, unless replaced or renewed on equally favourable terms, could adversely affect the Corporation’s results of operations and cash flows and increase the Corporation’s exposure to risks of price fluctuations in the wholesale power market.

Securing new Offtake Contracts is a risk factor in light of the competitive environment in which the Corporation operates. The Corporation expects the Renewable Energy Group to continue to enter into Offtake Contracts for the sale of its power, which Offtake Contracts are often obtained through participation in competitive requests for proposals processes. During these processes, the Corporation faces competitors ranging from large utilities to small independent power producers, some of which have significantly greater financial and other resources than the Corporation. There can be no assurance that the Corporation will be selected as power supplier following any particular request for proposals in the future or that existing Offtake Contracts will be renewed or will be renewed on favourable terms and conditions upon the expiry of their respective terms. Additionally, the Corporation is subject to the risk of impairment to its renewable power generation assets associated with potential declines in long term forecasted power prices for the period following the expiration of any Offtake Contract, as well as the expiration or decline in value of RECs and other sources of revenue.

Since the transmission and distribution of electricity is highly concentrated in most jurisdictions, there are a limited number of possible purchasers for utility-scale quantities of electricity in a given geographic location. As a result, there is a concentrated pool of potential buyers for electricity generated by the Renewable Energy Group’s businesses, which may restrict its ability to negotiate favourable terms under new Offtake Contracts and could impact its ability to find new customers for the electricity generated by its generation facilities should this become necessary. In the past few years, there has been increased participation from commercial and industrial businesses. The higher long-term business risk profile of these companies results in increased credit risk. Furthermore, if the financial condition of these utilities and/or power purchasers deteriorates or the renewable portfolio standards programs, climate change programs, carbon-reduction targets or other regulations or policies to which they are currently subject change, demand for electricity produced by the Renewable Energy Group’s business could be negatively impacted.

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The Corporation may fail to complete planned acquisitions, which may result in a loss of expected benefits from such acquisitions or may generate significant liabilities, and the pendency of planned acquisitions could adversely affect the business and operations of the Corporation and any acquired entities.

Acquisitions of businesses and technologies are a part of the Corporation’s overall business strategy. Because of the regulated nature of certain of the business sectors in which the Corporation operates, certain acquisitions by the Corporation, including the Kentucky Power Transaction, are subject to various regulatory approvals and, consequently, to the risks that such approvals may not be timely obtained or may impose unfavourable conditions that could impair the ability to complete the acquisition or impose adverse conditions on the Corporation in order to complete the acquisition. To the extent there are intervenors in the regulatory approval process, such intervenors’ filed positions in these dockets (including those dockets associated with the Kentucky Power Transaction) may increase these risks.

If the Kentucky Power Transaction is not completed, the Corporation could be subject to a number of risks that may adversely affect the Corporation’s business, financial condition, results of operations, reputation and cash flows, including (i) the requirement to pay costs relating to the Kentucky Power Transaction, including costs relating to the financing thereof and obtaining regulatory approval, and (ii) time and resources committed by the Corporation’s management to matters relating to the Kentucky Power Transaction that could otherwise have been devoted to pursuing other beneficial opportunities. In addition, if the Kentucky Acquisition Agreement for the Kentucky Power Transaction is terminated in certain circumstances, the Corporation may be required to pay a termination fee of $65 million. See “Material Contracts”.

In addition, the Corporation may pursue acquisition opportunities through participation in competitive auction processes. During these processes, the Corporation may face competition from other companies with greater purchasing power, capital or other resources or a greater willingness to accept lower returns or risk. The outcomes of such processes are uncertain and the Corporation may fail to win such bids.

Further, the Corporation may enter into acquisition agreements under which the Corporation’s obligations are not contingent upon availability of financing, in which case the Corporation could incur higher than expected financing costs or, if such financing cannot be obtained, significant liability to the seller.

In connection with a pending acquisition, including the Kentucky Power Transaction, certain clients, customers or counterparties of each of the Corporation and any entities to be acquired by the Corporation, including Kentucky Power, may delay or defer decisions, which could negatively impact the revenues, earnings, cash flows and expenses of the Corporation and such acquired entities, regardless of whether the acquisition is completed. Similarly, current and prospective employees of the Corporation and any acquired entities may experience uncertainty about their future roles following an acquisition, which may materially adversely affect the ability of each of the Corporation and such acquired entities to attract, retain and motivate key personnel during the pendency of an acquisition and which may materially adversely divert attention from the daily activities of the Corporation’s and the acquired entities’ existing employees. If key employees depart due to the uncertainty of employment and difficulty of integration or a desire not to remain with the combined company following completion of an acquisition, the Corporation may incur significant costs in identifying, hiring, and retaining replacements for departing employees, which could have a material adverse effect on the Corporation’s business operations and financial results.

The Corporation may fail to realize the intended benefits of completed acquisitions or may incur unexpected costs or liabilities as a result of completed acquisitions.

The Corporation may not effectively integrate the services, technologies, key personnel or businesses of acquired companies or may not obtain anticipated operating benefits or synergies from completed transactions. In addition, the Corporation may incur unexpected costs or liabilities in connection with the closing or integration of any acquisition.

When acquisitions occur, significant demands can be placed on the Corporation’s managerial, operational and financial personnel and systems. No assurance can be given that the Corporation’s systems, procedures and controls will be adequate to support the expansion of the Corporation’s operations resulting from the acquisition. The success of an acquisition may depend on retention of the workforce or key employees of the acquired business. The Corporation may not be successful in retaining such workforce or key employees or in retaining them at anticipated costs.

Further the Corporation may, following a transaction closing, rely on certain transition services to be provided by the seller, which may not be adequate for the Corporation to maintain the current operations of the acquired entities and facilitate the efficient and effective transition of business operations, nor can there be any assurance that the transition process will be completed during the term of the transition services agreement. If the transition process is not completed successfully, the operations and financial performance of the acquired entity may be negatively affected, which could adversely affect the business, results of operations and financial condition of the Corporation.

Business combinations such as the Kentucky Power Transaction involve risks that could materially and adversely affect the Corporation’s business plan, including the failure to realize the results that the Corporation expects. Transition and

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integration activities associated with this business combination may not go as planned, creating the potential for increased costs, service disruption, noncompliance, reputational harm and other negative outcomes. There can be no assurance that the Corporation will be successful in increasing the historical returns earned by either Kentucky Power or Kentucky TransCo, that the load declines experienced by Kentucky Power over recent years will not continue to be a prevailing trend, or that the Corporation will be able to fully realize some or all of the expected benefits of the Kentucky Power Transaction or succeed in implementing its strategic objectives relating to the acquired entities, including the success of the transfer of operational control of the Mitchell Plant from Kentucky Power to the Wheeling Power Company and the transition of Kentucky Power’s generating mix to greener sources (i.e. “greening the fleet” initiatives). The ability to realize these anticipated benefits and implement these strategic objectives will depend in part on successfully retaining staff, hiring additional staff to replace certain of the Sellers’ centralized operations, obtaining favourable regulatory outcomes, realizing growth opportunities, no unanticipated economic changes in the areas where the acquired entities operate, and potential synergies through the coordination of activities and operations with the Corporation’s existing business. There is a risk that some or all of the expected benefits and strategic objectives will fail to materialize, or may not occur within the time periods anticipated by the Corporation. A failure to realize the anticipated benefits of or implement strategic objectives relating to the Kentucky Power Transaction on an efficient and effective basis could have a material adverse effect on the Corporation’s financial condition, results of operations, reputation and cash flows.

Kentucky Power and Kentucky TransCo are party to agreements that contain change of control and/or termination for convenience provisions which may be triggered following completion of the Kentucky Power Transaction. The operation of these change of control or termination provisions, if triggered, could result in unanticipated expenses and/or cash payments following the consummation of the Kentucky Power Transaction or adversely affect the acquired entities’ results of operations and financial condition. Unless these change of control provisions are waived, or the termination provisions are not exercised, by the other party, the operation of any of these provisions could adversely affect the results of operations and financial condition of the Corporation and the acquired entities.

In addition, the Corporation may be subject to unexpected liabilities, including in respect of the Kentucky Power Transaction, despite any due diligence investigation of an acquired business or any contractual remedies the Corporation may have against the seller. Detailed information regarding an acquired business is generally available only from the seller, and contractual remedies are typically subject to negotiated limitations. Further, though the Corporation negotiates covenants regarding the operation of a target prior to closing, the Corporation will not control the target entity until completion of the transaction, and as a result the business and results of operations may be adversely affected by events that are outside of the Corporation’s control during the intervening period. In addition, in cases in which the target company is publicly traded and its shares are widely held, the Corporation is likely not to have recourse following the completion of the acquisition for misrepresentations made to the Corporation in connection with the acquisition.

With respect to the Kentucky Power Transaction, while the Corporation has accounted for unexpected liabilities or liabilities that it was unable to quantify for the purposes of making its decision to enter into the Kentucky Acquisition Agreement, there can be no assurance that any such liability will not exceed the Corporation’s estimates. In connection with the Kentucky Power Transaction, the Corporation has obtained a representation and warranty insurance policy, with coverage up to $255 million, subject to an initial retention of $21 million. Nevertheless, this insurance policy is subject to certain exclusions and limitations and there may be circumstances for which the insurer attempts to limit such coverage or refuses to indemnify the Corporation or where the coverage provided under the insurance policy may otherwise be insufficient or inapplicable.

The Corporation’s investment in Atlantica is subject to risks, including that the market price of Atlantica’s securities could decline or Atlantica may make decisions with which the Corporation does not agree or take risks or otherwise act in a manner that does not serve the Corporation’s interests.

The Corporation owns an equity interest in Atlantica of approximately 42%. This investment is subject to a risk that Atlantica may make business, financial or management decisions with which the Corporation does not agree, or that Atlantica’s other stockholders or management of Atlantica may take risks or otherwise act in a manner that does not serve the Corporation’s interests. On February 21, 2023, Atlantica announced that its board of directors has commenced a process to explore and evaluate potential strategic alternatives to maximize shareholder value (the “Atlantica Strategic Review”). There is a risk that the Atlantica Strategic Review could result in the approval or completion of a transaction or other change in Atlantica’s business strategy that is not aligned with the Corporation’s interests. If any of the foregoing were to occur, the value of the Corporation’s investment could decrease and the Corporation’s financial condition, results of operations and cash flows could be adversely affected.

Dividends declared and paid by Atlantica are made at the discretion of Atlantica’s board of directors. The Corporation does not control the board of directors of Atlantica. Therefore, there can be no assurance that dividends will continue to be paid on Atlantica’s ordinary shares, will continue to be paid at the same rate as they are currently being paid or will be paid at any specified target rate. A loss of Atlantica dividend income, as a result of any reduction or suspension by Atlantica of its dividend or in the event that the Corporation were to dispose of its equity interest in Atlantica, could have a material adverse impact on the Corporation’s cash flows and net income.

Demand in the capital markets for Atlantica’s ordinary shares can vary over time for numerous reasons outside of the Corporation’s control, including performance of the Atlantica business and changes in the prospects of Atlantica.

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Consequently, it may be difficult for the Corporation to dispose of all or any of its interest in Atlantica at favourable times or prices, or at all.

The Corporation’s investment in Atlantica and its international acquisition, development, construction and operating activities, including through the Liberty JV, expose the Corporation to certain risks that are particular to certain international markets.

Atlantica owns, manages and acquires renewable energy, conventional power, electric transmission lines and water assets in certain jurisdictions where the Corporation may not operate. The Corporation, through its investment in Atlantica, is indirectly exposed to certain risks that are particular to the markets in which it operates, including, but not limited to, risks related to: conditions in the global economy; changes to national and international laws, political, social and macroeconomic risks relating to the jurisdictions in which Atlantica operates, including in emerging markets, which could be subject to economic, social and political uncertainties; anti-bribery and anti-corruption laws and substantial penalties and reputational damage from any non-compliance therewith; significant currency exchange rate fluctuations; Atlantica’s ability to identify and/or consummate future acquisitions on favourable terms or at all; Atlantica’s inability to replace, on similar or commercially favourable terms, expiring or terminated offtake agreements; termination or revocation of Atlantica’s concession agreements or Offtake Contracts; and various other factors. These risks could affect the profitability and growth of Atlantica’s business, and ultimately the profitability of the Corporation’s anticipated investment therein.

The Corporation’s international activities and operations, including through the Liberty JV, expose the Corporation to similar risks and could likewise affect the profitability, financial condition and growth of the Corporation.

Increased external stakeholder activism could have an adverse effect on the Corporation’s business, operations or financial condition.

External stakeholders, including shareholders, are increasingly challenging companies in the areas of performance, climate change, sustainability, diversity, utility return on equity (in the case of investor-owned utilities) and executive compensation. Shareholder activism can arise in a variety of situations and take many forms, including making public demands that the Corporation consider certain strategic alternatives, engaging in public campaigns and advancing shareholder proposals to attempt to influence the Corporation’s governance, management, strategic direction or operations, and commencing proxy contests to attempt to elect activists’ representatives or others to the Corporation’s board of directors. Any such shareholder activism could result in substantial costs and the diversion of management’s and the Board’s attention from the Corporation’s business. Additionally, such shareholder activism could give rise to perceived uncertainties as to the Corporation’s future direction, strategy or leadership, hinder the execution of the Corporation’s business plans, harm the reputation of the Corporation, adversely affect the Corporation’s relationships with its existing or potential employees, customers, service providers, investors or other partners, result in the loss of potential business opportunities and make it more difficult to attract and retain qualified personnel. Also, the Corporation may be required to incur significant fees and other expenses related to activist shareholder matters, including for third-party advisors. AQN’s stock price could be subject to significant fluctuation or otherwise be adversely affected by the events, risks and uncertainties of any shareholder activism. Any of the foregoing could have a material adverse impact on the Corporation’s business, operations and financial condition.

The Corporation may not have sole control over the projects or facilities that it invests in with its partners or over the revenues and certain decisions associated with those projects or facilities, which may limit the Corporation’s flexibility and financial returns with respect to these projects.

The Corporation has, and may in the future continue to have, an equity interest of 50% or less and/or partners in certain projects and facilities, including those owned by the Liberty JV. As a result, the Corporation may not control such projects and facilities and its interest may be subject to the decision-making of third parties, and the Corporation may be reliant on a third party’s personnel, good faith, contractual compliance, expertise, historical performance, technical resources and information systems, proprietary information and judgment in providing the services. This may limit the Corporation’s flexibility and financial returns with respect to these projects and facilities, and create risks to the Corporation, including that the joint venture partner may:

•have economic or business interests or goals that are inconsistent with the Corporation’s economic or business interests or goals;

•take actions contrary to the Corporation’s policies or objectives with respect to the Corporation’s investments;

•contravene applicable anti-bribery laws that carry substantial penalties for non-compliance and could cause reputational damage and a material adverse effect on the business, financial position and results of operations of the joint venture and the Corporation;

•have to give its consent with respect to certain major decisions, including among others, decisions relating to funding and transactions with affiliates;

•become bankrupt, limiting its ability to meet calls for capital contributions and potentially making it more difficult to refinance or sell projects;

•become engaged in a dispute with the Corporation that might affect the Corporation’s ability to develop a project;

•have competing interests in the Corporation’s markets that could create conflict of interest issues; or

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•have different accounting policies than the Corporation.

The Liberty JV (through Liberty Development Energy Solutions B.V.) is a party to a secured credit facility in the amount of $306.5 million (the “Liberty JV Secured Credit Facility”) and holds a preference share ownership interest in AY Holdings. The Liberty JV Secured Credit Facility is collateralized through a pledge of Atlantica ordinary shares held by AY Holdings. A collateral shortfall would occur if the net obligation (as defined in the credit agreement) would equal or exceed 50% of the market value of such Atlantica shares. In the event of a collateral shortfall, the Liberty JV is required to prepay a portion of the loan or post additional collateral in cash to reduce the net obligation to 40% of the total collateral provided (the “Collateral Reset Level”). If the Liberty JV were unable to fund the collateral shortfall, or certain other events of default occur, the Liberty JV Secured Credit Facility lenders hold the right to sell Atlantica shares to pay amounts outstanding under the facility, including reducing the facility to the Collateral Reset Level. The Liberty JV Secured Credit Facility is repayable on demand if Atlantica ceases to be a public company or if certain other events are announced or completed that could restrict the Corporation’s ability to sell or transfer its Atlantica ordinary shares. If the Liberty JV were unable to repay the amounts owed, the lenders would have the right to realize on their collateral.

The Corporation may desire to sell businesses or assets, which may have an adverse effect on the Corporation’s business, operations or financial condition.

For financial, strategic and other reasons, the Corporation may from time to time dispose of, or desire to dispose of, businesses or assets (in whole or in part) that it owns. For instance, on January 12, 2023, AQN announced that it is targeting approximately $1 billion of asset sales. Any disposition by the Corporation may result in recognition of a loss upon such a sale and may result in a decrease to its revenues, cash flows and net income and a change to its business mix. In addition, the Corporation may not be able to dispose of businesses or assets that the Corporation desires to sell for financial, strategic and other business reasons at all or at a price acceptable to the Corporation. Failure to execute on any planned disposition may require the Corporation to seek alternative sources of funds or incur additional indebtedness, which may, among other things, cause rating agencies to re-evaluate or downgrade the Corporation’s existing credit ratings. Each of the foregoing items may have an adverse effect on the Corporation’s business, results of operations, cost of capital or financial condition.

The price of the Common Shares or the Corporation’s other securities may be volatile and the value of shareholders’ investments could decline.

The trading price and value of, and demand for, the Common Shares or the Corporation’s other securities may fluctuate and depend on a number of factors, including:

•the risk factors described in this AIF;

•general economic conditions internationally and within Canada and the United States, including changes in interest rates;

•changes in electricity and natural gas prices;

•weather and seasonal fluctuation in renewable energy resources and in demand for electricity, water and natural gas;

•actual or anticipated fluctuations in the Corporation’s quarterly and annual results and those of the Corporation’s competitors, including failure by the Corporation to achieve any earnings, dividend, capital expenditure or other financial guidance or outlook disclosed by the Corporation;

•the Corporation’s reputation, businesses, operations, results and prospects;

•the timing and amount of dividends, if any, declared on the Common Shares or the Corporation’s other securities;

•future issuances of Common Shares or other securities by the Corporation;

•acquisitions, dispositions and strategic alliances;

•market conditions in the energy industry;

•changes in government regulation, taxes, legal proceedings or other developments, including adverse or unexpected decisions by regulatory authorities;

•changes in the credit ratings of the Corporation or any of its subsidiaries;

•sales of Common Shares or other securities of the Corporation by insiders;

•shortfalls in the Corporation’s operating results from levels forecasted by securities analysts;

•investor sentiment toward the stock of utility or renewable energy companies in general;

•announcements concerning the Corporation or its competitors;

•maintenance of acceptable credit ratings or credit quality; and

•the general state of the securities markets.

These and other factors may impair the development or sustainability of a liquid market for the Common Shares or the Corporation’s other securities and the ability of investors to sell Common Shares or the Corporation’s other securities at an attractive price. These factors also could cause the market price and demand for the Common Shares or the Corporation’s other securities to fluctuate substantially, which may adversely affect the price and liquidity of the Common Shares or the Corporation’s other securities. These fluctuations could cause shareholders to lose all or part of

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their investment in Common Shares or the Corporation’s other securities. Many of these factors and conditions are beyond the Corporation’s control and may not be related to its operating performance.

If securities or industry analysts do not publish research or publish inaccurate or unfavourable research about the Corporation or its businesses, the price and trading volume of the Common Shares or the Corporation’s other securities could decline.

The trading market for the Common Shares and the Corporation’s other securities will, to some extent, be impacted by the research and reports that securities or industry analysts publish about the Corporation or its business. The Corporation does not have any control over these publications. If one or more of the analysts who cover the Corporation should downgrade the Common Shares or the Corporation’s other securities or change their opinion of the Corporation’s business prospects or report inaccurate information, the Common Share price or the price of the Corporation’s other securities may decline. If one or more of these analysts cease coverage of the Corporation or fail to publish reports on the Corporation regularly, demand for the Common Shares or the Corporation’s other securities could decrease, which may cause the price and trading volume of the Common Shares or the Corporation’s other securities to decline.

5.DIVIDENDS

5.1Common Shares

The aggregate annual amount of dividends declared for each Common Share for fiscal 2020, 2021 and 2022 was $0.61, $0.67 and $0.71, respectively.

AQN follows a quarterly dividend schedule, subject to subsequent Board declarations each quarter. AQN’s current quarterly dividend to shareholders is $0.1085 per Common Share or $0.4340 per Common Share on an annualized basis (based on the current quarterly dividend).

There are no restrictions on the dividend policy of AQN. The amount of dividends declared and paid is ultimately determined by the Board and is dependent on a number of factors, including the risk factors previously noted. There can be no assurance as to the amount or timing of such dividends in the future. See “Enterprise Risk Factors”.

5.2Preferred Shares

On November 9, 2012, AQN issued 4,800,000 cumulative rate reset Series A preferred shares (the “Series A Shares”). Holders of Series A Shares are entitled to receive fixed cumulative preferential cash dividends, as and when declared by the Board, payable quarterly on the last business day of March, June, September and December in each year. In each of 2020, 2021 and 2022, dividends were paid at an annual rate equal to C$1.2905 per Series A Share. For the current five-year period from December 31, 2018 to December 31, 2023, the annual rate of the dividends is equal to C$1.2905 per Series A Share.

On January 1, 2013, the Corporation issued 100 Series C preferred shares (the “Series C Shares”) and exchanged such shares for the 100 Class B units of St. Leon LP. The Series C Shares provide dividends essentially identical to those expected from the Class B units. In 2020, 2021, and 2022, dividends paid to holders of Series C Shares were C$13,126.52, C$13,224.36 and C$13,688.16, respectively, per Series C Share.

On March 5, 2014, AQN issued 4,000,000 cumulative rate reset Series D preferred shares (the “Series D Shares”). Holders of Series D Shares are entitled to receive fixed cumulative preferential cash dividends, as and when declared by the Board, payable quarterly on the last business day of March, June, September and December in each year. In 2020, 2021 and 2022, dividends were paid at an annual rate equal to C$1.2728 per Series D Share. For the current five-year period from March 31, 2019 to March 31, 2024, the annual rate of the dividends is equal to C$1.2728 per Series D Share.

5.3Dividend Reinvestment Plan

AQN has a shareholder dividend reinvestment plan (the “Reinvestment Plan”) in respect of the Common Shares. However, effective March 16, 2023, AQN suspended the Reinvestment Plan. If AQN elects to reinstate the Reinvestment Plan in the future, shareholders who were enrolled in the Reinvestment Plan at its suspension and remain enrolled at reinstatement will automatically resume participation in the Reinvestment Plan. When the Reinvestment Plan is active, holders of Common Shares who reside in Canada, the United States, or, subject to AQN’s consent, other jurisdictions, may opt to reinvest the cash dividends paid on their Common Shares in additional Common Shares which, at AQN’s election, are either purchased on the open market or newly issued from treasury.

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6.DESCRIPTION OF CAPITAL STRUCTURE

6.1Common Shares

The Common Shares are publicly traded on the TSX and the NYSE under the ticker symbol “AQN”. As at December 31, 2022, AQN had 683,614,803 issued and outstanding Common Shares.

AQN may issue an unlimited number of Common Shares. The holders of Common Shares are entitled to dividends, if and when declared; to one vote for each Common Share at meetings of the holders of Common Shares; and to receive a pro rata share of any remaining property and assets of AQN upon liquidation, dissolution or winding up of AQN. All Common Shares are of the same class and with equal rights and privileges and are not subject to future calls or assessments.

6.2Preferred Shares

AQN is also authorized to issue an unlimited number of preferred shares, issuable in one or more series, containing terms and conditions as approved by the Board. As at December 31, 2022, AQN had outstanding:

•4,800,000 Series A Shares, yielding 5.162% annually for the five-year period ending on December 31, 2023;

•100 Series C Shares; and

•4,000,000 Series D Shares, yielding 5.091% annually for the five-year period ending on March 31, 2024.

As at December 31, 2022, no Series B Shares, Series E Shares, Series F Shares, Series G Shares, Series H Shares, or Series I Shares were outstanding.

Series A Shares

The Series A Shares rank senior to the Common Shares and rank on parity with every other series of preferred shares as to dividends, may be redeemed by AQN on December 31, 2023 and every five years thereafter and are convertible upon the occurrence of certain events into cumulative floating rate preferred shares, Series B (the “Series B Shares”). The Series A Shares were redeemable by AQN on December 31, 2018 (the “Series A Shares Redemption Right”), but AQN elected not to exercise its redemption right. The Series A Shares rank on parity with the preferred shares of every other series and senior to the Common Shares upon liquidation, dissolution or winding up of AQN. The Series A Shares are entitled to receive C$25.00 per Series A Share plus all accrued and unpaid dividends thereon, but are not entitled to share in any further distribution of the assets of AQN.

Series B Shares

AQN is authorized to issue up to 4,800,000 Series B Shares upon the conversion of Series A Shares upon the occurrence of certain events. The Series B Shares rank senior to the Common Shares and rank on parity with every other series of preferred shares as to dividends, may be redeemed by AQN on any Series B Conversion Date (as defined in the articles of AQN), and are convertible into Series A Shares upon the occurrence of certain events. The Series B Shares rank on parity with the preferred shares of every other series and senior to the Common Shares upon liquidation, dissolution or winding up of AQN. The Series B Shares are entitled to receive C$25.00 per Series B Share plus all accrued and unpaid dividends thereon, but are not entitled to share in any further distribution of the assets of AQN. Upon AQN’s election not to exercise the Series A Shares Redemption Right, the holders of the Series A Shares had the right to convert all or part of their Series A Shares into Series B Shares on December 31, 2018. However, since less than the required minimum of 1,000,000 Series A Shares were tendered for conversion, none of the Class A Shares were converted into Class B Shares and no Class B Shares have been issued by AQN.

Series C Shares

The Series C Shares rank senior to the Common Shares and rank on parity with every other series of preferred shares as to dividends and are entitled to cumulative dividends in accordance with the formula set forth in the articles of AQN. The Series C Shares rank on parity with the preferred shares of every other series and senior to the Common Shares upon liquidation, dissolution or winding up of AQN. The Series C Shares are entitled to receive the redemption price calculated in accordance with the share terms plus all accrued and unpaid dividends thereon, but are not entitled to share in any further distribution of the assets of AQN. The Series C Shares are redeemable upon the occurrence of certain events. During the period between May 20, 2031 and June 19, 2031, the Series C Shares are convertible into Common Shares and, if not so converted, will be automatically redeemed on June 19, 2031.

Series D Shares

The Series D Shares rank senior to the Common Shares and rank on parity with every other series of preferred shares as to dividends, may be redeemed by AQN on March 31, 2024 and every five years thereafter, and are convertible upon the occurrence of certain events into cumulative floating rate preferred shares, Series E (the “Series E Shares”). The Series D Shares were redeemable by AQN on April 1, 2019 (the “Series D Shares Redemption Right”), but AQN elected not to

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exercise its redemption right. The Series D Shares rank on parity with the preferred shares of every other series and senior to the Common Shares upon liquidation, dissolution or winding up of AQN. The Series D Shares are entitled to receive C$25.00 per Series D Share plus all accrued and unpaid dividends thereon, but are not entitled to share in any further distribution of the assets of AQN.

Series E Shares

AQN is authorized to issue up to 4,000,000 Series E Shares upon the conversion of Series D Shares upon the occurrence of certain events. The Series E Shares rank senior to the Common Shares and rank on parity with every other series of preferred shares as to dividends, may be redeemed by AQN on any Series E Conversion Date (as defined in the articles of AQN), and are convertible into Series D Shares upon the occurrence of certain events. The Series E Shares rank on parity with the preferred shares of every other series and senior to the Common Shares upon liquidation, dissolution or winding up of AQN. The Series E Shares are entitled to receive C$25.00 per Series E Share plus all accrued and unpaid dividends thereon, but are not entitled to share in any further distribution of the assets of AQN. Upon AQN’s election not to exercise the Series D Shares Redemption Right, the holders of the Series D Shares had the right to convert all or part of their Series D Shares into Series E Shares on April 1, 2019. However, since less than the required minimum of 1,000,000 Series D Shares were tendered for conversion, none of the Class D Shares were converted into Class E Shares and no Class E Shares have been issued by AQN.

Series F Shares

AQN is authorized to issue an unlimited number of preferred shares, Series F of AQN (the “Series F Shares”) following the conversion of the AQN’s 6.875% fixed-to-floating subordinated notes – Series 2018-A (the “2018 Subordinated Notes”) upon the occurrence of certain bankruptcy-related events. The Series F Shares rank senior to the Common Shares and rank on parity with every other series of preferred shares as to dividends and may be redeemed by AQN, subject to certain restrictions, at any time after October 17, 2023. The Series F Shares rank on parity with the preferred shares of every other series and senior to the Common Shares upon liquidation, dissolution or winding up of AQN. The Series F Shares are entitled to receive $25.00 per Series F Share plus all accrued and unpaid dividends thereon, but are not entitled to share in any further distribution of the assets of AQN.

Series G Shares

AQN is authorized to issue an unlimited number of Series G Shares (the “Series G Shares”) following the conversion of AQN’s 6.2% fixed-to-floating subordinated notes – Series 2019-A (the “2019 Subordinated Notes”) upon the occurrence of certain bankruptcy-related events. The Series G Shares rank senior to the Common Shares and rank on parity with every other series of preferred shares as to dividends and may be redeemed by AQN, subject to certain restrictions, at any time after July 1, 2024. The Series G Shares rank on parity with the preferred shares of every other series and senior to the Common Shares upon liquidation, dissolution or winding up of AQN. The Series G Shares are entitled to receive $25.00 per Series G Share plus all accrued and unpaid dividends thereon, but are not entitled to share in any further distribution of the assets of AQN.

Series H Shares

AQN is authorized to issue an unlimited number of Series H Shares following the conversion of the 2022-A Subordinated Notes upon the occurrence of certain bankruptcy-related events. The Series H Shares rank senior to the Common Shares and rank on parity with every other series of preferred shares as to dividends and may be redeemed by AQN, subject to certain restrictions, at any time after October 18, 2031. The Series H Shares rank on parity with the preferred shares of every other series and senior to the Common Shares upon liquidation, dissolution or winding up of AQN. The Series H Shares are entitled to receive C$1,000 per share (less any amount that may have been returned to holders as a return of capital), together with all accrued and unpaid dividends, but are not entitled to share in any further distribution of the assets of AQN.

Series I Shares

AQN is authorized to issue an unlimited number of Series I Shares following the conversion of the 2022-B Subordinated Notes upon the occurrence of certain bankruptcy-related events. The Series I Shares rank senior to the Common Shares and rank on parity with every other series of preferred shares as to dividends and may be redeemed by AQN, subject to certain restrictions, at any time after January 18, 2027. The Series I Shares rank on parity with the preferred shares of every other series and senior to the Common Shares upon liquidation, dissolution or winding up of AQN. The Series I Shares are entitled to receive $1,000 per share (less any amount that may have been returned to holders as a return of capital), together with all accrued and unpaid dividends, but are not entitled to share in any further distribution of the assets of AQN.

Subject to applicable corporate law, the outstanding preferred shares are non-voting and not entitled to receive notice of any meeting of shareholders, except that the Series A Shares (and the Series B Shares into which they are convertible) and Series D Shares (and Series E Shares into which they are convertible), the Series F Shares and the Series G Shares will be entitled to one vote per share if AQN shall have failed to pay eight quarterly dividends on such shares, and the Series H Shares and the Series I Shares will be entitled to four one-hundredths of a vote in respect of each $1.00 of the issue price of each such share if AQN shall have failed to pay four semi-annual dividends on such shares.

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6.3Subordinated Notes

2018 Subordinated Notes

On October 17, 2018, AQN completed the sale of $287.5 million aggregate principal amount of 2018 Subordinated Notes. The 2018 Subordinated Notes are publicly traded on the NYSE under the ticker symbol “AQNA”.

The Corporation will pay interest on the 2018 Subordinated Notes at a fixed rate of 6.875% per year in equal quarterly installments until October 17, 2023. Starting on October 17, 2023, and quarterly on every January 17, April 17, July 17 and October 17 of each year during which the 2018 Subordinated Notes are outstanding thereafter until October 17, 2078 (each such date, a “2018 Notes Interest Reset Date”), the interest rate on the 2018 Subordinated Notes will be reset to an interest rate per annum equal to (i) starting on October 17, 2023, on every 2018 Notes Interest Reset Date until October 17, 2028, the three month LIBOR plus 3.677%, payable in arrears, (ii) starting on October 17, 2028, on every 2018 Notes Interest Reset Date until October 17, 2043, the three month LIBOR plus 3.927%, payable in arrears, and (iii) starting on October 17, 2043, on every 2018 Notes Interest Reset Date until October 17, 2078, the three month LIBOR plus 4.677%, payable in arrears. So long as no event of default has occurred and is continuing, AQN may elect to defer the interest payable on the 2018 Subordinated Notes on one or more occasions for up to five consecutive years.

The 2018 Subordinated Notes have a maturity date of October 17, 2078. On or after October 17, 2023, AQN may, at its option, redeem the 2018 Subordinated Notes at a redemption price equal to 100% of the principal amount thereof, together with accrued and unpaid interest.

Upon the occurrence of certain bankruptcy-related events in respect of AQN, the 2018 Subordinated Notes automatically convert into Series F Shares.

2019 Subordinated Notes

On May 23, 2019, AQN completed the sale of $350 million aggregate principal amount of 2019 Subordinated Notes. The 2019 Subordinated Notes are publicly traded on the NYSE under the ticker symbol “AQNB”.

The Corporation will pay interest on the 2019 Subordinated Notes at a fixed rate of 6.2% per year in equal quarterly installments until July 1, 2024. Starting on July 1, 2024, and quarterly on every January 1, April 1, July 1 and October 1 of each year during which the 2019 Subordinated Notes are outstanding thereafter until July 1, 2079 (each such date, a “2019 Notes Interest Reset Date”), the interest rate on the 2019 Subordinated Notes will be reset to an interest rate per annum equal to (i) starting on July 1, 2024, on every 2019 Notes Interest Reset Date until July 1, 2029, the three month LIBOR plus 4.01%, payable in arrears, (ii) starting on July 1, 2029, on every 2019 Notes Interest Reset Date until July 1, 2049, the three month LIBOR plus 4.26%, payable in arrears, and (iii) starting on July 1, 2049, on every 2019 Notes Interest Reset Date until July 1, 2079, the three month LIBOR plus 5.01%, payable in arrears. So long as no event of default has occurred and is continuing, AQN may elect to defer the interest payable on the 2019 Subordinated Notes on one or more occasions for up to five consecutive years.

The 2019 Subordinated Notes have a maturity date of July 1, 2079. On or after July 1, 2024, AQN may, at its option, redeem the 2019 Subordinated Notes at a redemption price equal to 100% of the principal amount thereof, together with accrued and unpaid interest.

Upon the occurrence of certain bankruptcy-related events in respect of AQN, the 2019 Subordinated Notes automatically convert into Series G Shares.

2022-A Subordinated Notes

On January 18, 2022, AQN completed the sale of C$400 million aggregate principal amount of 2022-A Subordinated Notes. The Corporation will pay interest on the 2022-A Subordinated Notes semi-annually in arrears on January 18 and July 18 of each year during which the 2022-A Subordinated Notes are outstanding until January 18, 2082 (each such semi-annual date, a “2022-A Interest Payment Date”).

The 2022-A Subordinated Notes will bear interest, from, and including, January 18, 2022 to, but excluding, January 18, 2032, at a fixed rate of 5.25% per year. Starting on January 18, 2032, and on every fifth anniversary of such date thereafter (each such date, a “2022-A Notes Interest Reset Date”), the interest rate on the 2022-A Subordinated Notes will be reset to an interest rate per annum equal to the 5-Year Government of Canada Yield on the business day immediately preceding such 2022-A Notes Interest Reset Date plus, (i) for the period from, and including, January 18, 2032 to, but excluding, January 18, 2052, 3.717%, and (ii) for the period from, and including, January 18, 2052 to, but excluding, January 18, 2082, 4.467%, in each case, to be reset on each 2022-A Notes Interest Reset Date. So long as no event of default has occurred and is continuing, AQN may elect to defer the interest payable on the 2022-A Subordinated Notes on one or more occasions for up to five consecutive years.

The 2022-A Subordinated Notes have a maturity date of January 18, 2082. From October 18, 2031 to January 18, 2032, and thereafter, on any 2022-A Interest Payment Date, AQN may, at its option, redeem the 2022-A Subordinated Notes at a redemption price equal to 100% of the principal amount thereof, together with accrued and unpaid interest. Prior to October 18, 2031, the Corporation may, at its option, redeem the 2022-A Subordinated Notes at a redemption price equal to 100% of the principal amount of the 2022-A Subordinated Notes to be redeemed, plus a “make-whole” premium and accrued and unpaid interest, if any.

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Upon the occurrence of certain bankruptcy-related events in respect of AQN, the 2022-A Subordinated Notes automatically convert into Series H Shares.

2022-B Subordinated Notes

On January 18, 2022, AQN completed the sale of $750 million aggregate principal amount of 2022-B Subordinated Notes. The Corporation will pay interest on the 2022-B Subordinated Notes semi-annually in arrears on January 18 and July 18 of each year during which the 2022-B Subordinated Notes are outstanding until January 18, 2082.

The 2022-B Subordinated Notes will bear interest, from, and including, January 18, 2022 to, but excluding, April 18, 2027, at a fixed rate of 4.75% per year. Starting on April 18, 2027, and on every fifth anniversary of such date thereafter (each such date, a “2022-B Notes Interest Reset Date”), the interest rate on the 2022-B Subordinated Notes will be reset to an interest rate per annum equal to the Five-Year U.S. Treasury Rate on the business day immediately preceding such 2022-B Notes Interest Reset Date plus, (i) for the period from, and including, April 18, 2027 to, but excluding, April 18, 2032, 3.249%, (ii) for the period from, and including, April 18, 2032 to, but excluding, April 18, 2052, 3.499%, and (iii) for the period from, and including, April 18, 2052 to, but excluding, January 18, 2082, 4.249%, in each case, to be reset on each 2022-B Notes Interest Reset Date. So long as no event of default has occurred and is continuing, AQN may elect to defer the interest payable on the 2022-B Subordinated Notes on one or more occasions for up to five consecutive years.

The 2022-B Subordinated Notes have a maturity date of January 18, 2082. From, and including, the January 18 immediately preceding a 2022-B Notes Interest Reset Date to, and including, that particular 2022-B Notes Interest Reset Date (each such period, a “Par Call Period”), AQN may, at its option, redeem the 2022-B Subordinated Notes at a redemption price equal to 100% of the principal amount thereof, together with accrued and unpaid interest. At any time not during a Par Call Period, the Corporation may, at its option, redeem the 2022-B Subordinated Notes at a redemption price equal to 100% of the principal amount of the 2022-B Subordinated Notes to be redeemed, plus a “make-whole” premium and accrued and unpaid interest, if any.

Upon the occurrence of certain bankruptcy-related events in respect of AQN, the 2022-B Subordinated Notes automatically convert into Series I Shares.

6.4Equity Units

As at December 31, 2022, AQN had 23,000,000 Equity Units outstanding. The Equity Units (that are in the form of “corporate units”) are publicly traded on the NYSE under the ticker symbol “AQNU”.

Each Equity Unit was issued in a stated amount of $50 and, at issuance, consisted of a 1/20 or 5% undivided beneficial interest in a $1,000 principal amount 1.18% remarketable senior note of the Corporation due June 15, 2026, and a contract to purchase Common Shares on June 15, 2024 based on a reference price determined by the volume-weighted average Common Share price over the preceding 20 day trading period. Total annual distributions on the Equity Units are at the rate of 7.75%, consisting of quarterly interest payments on the remarketable senior notes at a rate of 1.18% per year and, subject to any permitted deferral, quarterly contract adjustment payments on the purchase contracts at a rate of 6.57% per year. The reference price for the Equity Units is $15.00 per Common Share. The minimum settlement rate under each purchase contract is 2.7778 Common Shares and the maximum settlement rate is 3.3333 Common Shares, resulting in a minimum of 63,889,400 Common Shares and a maximum of 76,665,900 Common Shares issuable on settlement of the purchase contracts. These settlement rates are subject to adjustment in certain circumstances.

6.5Shareholders’ Rights Plan

The shareholders’ rights plan, as amended and restated in 2022 (the “Amended and Restated Rights Plan”) is intended to ensure the fair treatment of shareholders in any transaction involving a potential change of control of AQN and will provide the Board and shareholders with adequate time to evaluate any unsolicited take-over bid and, if appropriate, to seek out alternatives to maximize shareholder value.

Until the occurrence of certain specific events, the rights will trade with the Common Shares and be represented by certificates representing the Common Shares. The rights become exercisable only when a person, including any party related to it or acting jointly with it (subject to certain exceptions), acquires or announces its intention to acquire 20% or more of the outstanding Common Shares without complying with the permitted bid provisions of the Amended and Restated Rights Plan. Should a non-permitted bid be launched, each right would entitle each holder of shares (other than the acquiring person and persons related to it or acting jointly with it) to purchase additional Common Shares at a 50% discount to the market price at the time.

It is not the intention of the Amended and Restated Rights Plan to prevent take-over bids but to ensure their proper evaluation by the market. Under the Amended and Restated Rights Plan, a permitted bid is a bid made to all shareholders for all of their Common Shares on identical terms and conditions that is open for no less than 105 days. If at the end of 105 days at least 50% of the outstanding Common Shares, other than those owned by the offeror and certain related parties, have been tendered and not withdrawn, the offeror may take up and pay for the Common Shares but must extend the bid for a further 10 days to allow all other shareholders to tender.

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The Amended and Restated Rights Plan will remain in effect until the termination of the annual meeting of the shareholders of AQN in 2025 (unless extended by approval of the shareholders at such meeting) or its termination under the terms of the Amended and Restated Rights Plan.

7.MARKET FOR SECURITIES

7.1Trading Price and Volume

7.1.1Common Shares

The Common Shares are listed and posted for trading on the TSX and NYSE under the symbol “AQN”. The following table sets forth the high and low trading prices and the aggregate volumes of trading of the Common Shares for the periods indicated (as quoted by the TSX and NYSE).


		TSX			NYSE
2022	High (C$)	Low (C$)	Volume	High ($)	Low ($)	Volume
January	18.35	17.14	48,378,280	14.46	13.51	12,879,793
February	18.45	17.43	34,087,838	14.56	13.59	10,541,538
March	19.58	18.18	62,236,158	15.66	14.30	15,020,478
April	20.19	18.56	68,223,059	16.01	14.45	10,343,602
May	18.83	17.32	50,628,271	14.73	13.27	17,212,711
June	18.65	16.75	51,750,037	14.85	12.89	17,695,187
July	18.00	17.01	35,074,758	14.05	13.03	11,162,691
August	18.79	17.79	25,957,781	14.65	13.68	8,994,674
September	18.27	15.03	50,274,412	13.95	10.91	12,055,732
October	16.02	13.86	55,989,920	11.78	9.94	17,416,739
November	15.37	9.86	144,188,731	11.51	7.26	33,357,043
December	10.36	8.70	119,071,450	7.71	6.41	41,213,224

7.1.2Preferred Shares

Series A Shares

The Series A Shares are listed and posted for trading on the TSX under the symbol “AQN.PR.A”. The following table sets forth the high and low trading prices and the aggregate volume of trading of the Series A Shares for the periods indicated (as quoted by the TSX).


2022	High (C$)	Low (C$)	Volume
January	26.15	24.71	57,110
February	25.56	24.61	47,589
March	25.59	24.42	41,180
April	25.11	21.41	120,321
May	24.05	22.23	70,282
June	24.50	22.52	176,718
July	22.89	20.77	44,543
August	23.20	21.43	30,689
September	23.25	20.16	44,870
October	20.79	16.86	303,809
November	20.34	17.90	139,679
December	19.57	17.71	121,101

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Series D Shares

The Series D Shares are listed and posted for trading on the TSX under the symbol “AQN.PR.D”. The following table sets forth the high and low trading prices and the aggregate volume of trading of the Series D Shares for the periods indicated (as quoted by the TSX).


2022	High (C$)	Low (C$)	Volume
January	26.45	24.88	74,452
February	25.98	24.92	41,073
March	25.80	24.80	63,652
April	25.26	22.21	66,349
May	25.14	22.37	147,791
June	25.30	23.86	58,753
July	24.20	21.90	24,267
August	24.35	22.70	39,567
September	24.33	21.70	40,891
October	21.98	17.99	281,188
November	20.30	18.56	135,610
December	19.60	18.10	222,571

7.1.3Subordinated Notes

2018 Subordinated Notes

The 2018 Subordinated Notes are listed and posted for trading on the NYSE under the symbol “AQNA”. The following table sets forth the high and low trading prices and the aggregate volume of trading of the 2018 Subordinated Notes for the periods indicated (as quoted by the NYSE).


2022	High ($)	Low ($)	Volume
January	26.78	26.14	618,169
February	27.10	25.05	550,452
March	26.55	25.29	935,095
April	26.41	24.82	460,458
May	26.48	25.00	593,581
June	25.82	23.51	463,860
July	25.94	24.58	197,738
August	26.22	24.01	281,663
September	25.37	23.75	476,867
October	24.83	20.69	982,850
November	24.44	22.17	716,874
December	24.85	22.75	506,444

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2019 Subordinated Notes

The 2019 Subordinated Notes are listed and posted for trading on the NYSE under the symbol “AQNB”. The following table sets forth the high and low trading prices and the aggregate volume of trading of the 2019 Subordinated Notes for the periods indicated (as quoted by the NYSE).


2022	High ($)	Low ($)	Volume
January	27.31	26.37	488,748
February	26.95	25.19	398,475
March	27.13	25.19	952,588
April	26.32	24.88	567,601
May	25.98	23.99	438,726
June	25.86	23.55	386,233
July	25.73	23.68	304,030
August	26.80	23.59	392,391
September	24.97	23.45	418,143
October	24.43	21.02	384,119
November	23.90	21.26	894,938
December	23.35	21.08	510,663

7.1.4Equity Units

The Equity Units are listed and posted for trading on the NYSE under the symbol “AQNU”. The following table sets forth the high and low trading prices and the aggregate volume of trading of the Equity Units for the periods indicated (as quoted by the NYSE).


2022	High ($)	Low ($)	Volume
January	47.05	44.63	5,415,936
February	46.75	44.60	1,112,421
March	49.57	45.56	1,366,628
April	50.49	46.65	1,034,778
May	47.34	43.53	1,482,262
June	46.69	41.88	1,888,037
July	45.88	43.00	550,345
August	47.14	44.27	1,922,802
September	44.94	37.46	758,238
October	40.92	35.15	658,648
November	39.34	25.30	5,246,201
December	26.62	22.79	2,649,378

7.2Prior Sales

On January 18, 2022, AQN completed an underwritten offering of (i) C$400 million of 2022-A Subordinated Notes and (ii) $750 million of 2022-B Subordinated Notes.

7.3Escrowed Securities and Securities Subject to Contractual Restrictions on Transfer

There are no securities of AQN that are, to AQN’s knowledge, held in escrow or subject to contractual restrictions on transfer as of the date of this AIF.

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8.DIRECTORS AND OFFICERS

8.1Name, Occupation and Security Holdings

The following table sets forth certain information with respect to the directors and executive officers of AQN as of the date of this AIF, and information on their history with the Corporation.


Name and Place of Residence	Principal Occupation	Served as Director or Officer of AQN from
ARUN BANSKOTA Oakville, Ontario Canada	Arun Banskota is the President & Chief Executive Officer of AQN. He initially joined AQN as President in February 2020. Mr. Banskota has over 30 years of progressively senior roles with experience in energy development, construction, financing, and operations; profit and loss management of multiple large business units; and three start-ups in the clean-tech space. Prior to joining AQN, Mr. Banskota was Vice President, Data Center Global Services and Energy Team at Amazon.com, where he was responsible for the planning, engineering, and delivery of datacenter capacity for Amazon Web Services, a high growth global market-leader of cloud services. As Managing Director of Global Power at El Paso Corporation, he had profit and loss responsibility for a 6,500 MW global portfolio of 32 power plants, project development and approximately 10,000 employees. He was on the leadership team for a large energy company and has successfully managed project development, financing, and operations for solar, wind, and natural gas projects. As President & CEO of EVgo, Mr. Banskota was responsible for taking commercial a high growth start-up company to build scale and presence in the electrical vehicle infrastructure sector. Mr. Banskota also serves on the board of directors of Atlantica. Mr. Banskota holds a Master of Arts from the University of Denver, and a Master of Business Administration from the University of Chicago.	Officer of AQN since February 10, 2020 and Director of AQN since July 17, 2020
MELISSA STAPLETON BARNES Carmel, Indiana, United States	Melissa Stapleton Barnes was formerly Senior Vice President, Enterprise Risk Management, and Chief Ethics and Compliance Officer for Eli Lilly and Company, a global, research-based pharmaceutical company. In this role from January 2013 through June 2021, she was an executive officer and served as a member of the company’s executive committee. During her nearly 27-year career with Eli Lilly and Company, she also held a variety of business operations and legal positions, including the role of Vice President and Deputy General Counsel from 2012 to 2013; and General Counsel, Lilly Diabetes and Lilly Oncology from 2010 to 2012. Ms. Barnes holds a Bachelor of Science in Political Science and Government (highest distinction) from Purdue University and a Juris Doctorate from Harvard Law School. She is a Licensed Attorney with the Indiana State Bar, serves on the Dean’s Advisory Council for Purdue University’s College of Liberal Arts, and is on the board of the Ethics Research Council. Ms. Barnes is also Past Chair of the Ethics and Business Integrity Committee for the International Federation of Pharmaceutical Manufacturers and Associations.	Director of AQN since June 9, 2016
HELEN BREMNER Calgary, Alberta Canada	Helen Bremner is the Executive Vice President, Strategy and Sustainability of AQN. Ms. Bremner has over 25 years of experience in strategy consulting and executive management in the utilities and energy sectors in Canada, the United States, Australia, and New Zealand. Prior to joining AQN, Ms. Bremner was a Partner (retired) at PwC Strategy& where she led the energy, utilities, mining and industrials practice in Canada. Previous experiences include five years as an Executive Vice President with ENMAX, 15 years in C-Suite roles with Meridian Energy and TransAlta in New Zealand and seven years with Andersen Consulting Strategy practice in Australia and Booz Allen and Hamilton in the U.S. Ms. Bremner holds a Master of Business Administration from the University of Chicago, a Master of Arts (Honours) from the University of St Andrews Scotland, and attended the Stanford Executive Program at the Stanford University Graduate School of Business. She also holds certification from the New Zealand Institute of Directors.	Officer of AQN since November 15, 2021

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AMEE CHANDE West Vancouver, British Columbia Canada	Amee Chande is a corporate director and strategy consultant. Ms. Chande is a senior advisor to leading companies in the mobility sector such as ChargePoint. In 2019, Ms. Chande was Chief Commercial Officer for Waymo, Google’s self-driving car project, where she was responsible for defining the overall strategy and laying the foundation for a strong commercial business. From 2015 to 2018, she was a Managing Director at Alibaba Group where she was the first senior executive hired to lead globalization. Ms. Chande has also held divisional Managing Director and Chief Executive Officer roles at global retailers including Tesco, Staples, and Wal-Mart, in both Europe and the United States. She began her career as a strategy consultant with McKinsey & Company. Ms. Chande serves on the Advisory Board of Livingbridge Private Equity, is a director of Air Canada and Thumbtack, Inc., and is a volunteer with the World Association of Girl Guides and Girl Scouts where she recently completed her term as a member of the World Board. Ms. Chande holds a Bachelor of Business Administration degree from Simon Fraser University, a Master of Science degree from the London School of Economics, and a Master of Business Administration from Harvard Business School.	Director of AQN since June 2, 2022
DAN GOLDBERG Ottawa, Ontario Canada	Dan Goldberg has been the President and Chief Executive Officer of Telesat Corporation since 2006. Prior to joining Telesat, Mr. Goldberg served as Chief Executive Officer of SES New Skies, a position he held following the purchase of New Skies by SES. During that time, Mr. Goldberg also served as a member of the SES Executive Committee. Prior to becoming Chief Executive Officer, he served as Chief Operating Officer of New Skies and prior to that as New Skies’ General Counsel. Before joining New Skies, Mr. Goldberg served as Associate General Counsel and Vice President of Government and Regulatory Affairs at PanAmSat. He began his career as an associate at Covington & Burling and then Goldberg, Godles, Wiener & Wright, law firms in Washington D.C. Mr. Goldberg obtained a Bachelor of Arts in History from the University of Virginia and a Juris Doctor from Harvard Law School.	Director of AQN since March 28, 2022
CHRIS HUSKILSON Wellington, Nova Scotia, Canada	Chris Huskilson is the President and CEO of 5-H Holdings Inc. and Chair of XOCEAN Ltd. An engineer by training, Mr. Huskilson was President and CEO of Emera Inc. for 13 years, over which time he took the business from approximately $3 billion to approximately $30 billion in assets. Recently, Mr. Huskilson has been active in the Atlantic Canadian start-up ecosystem, and is a founding partner at Creative Destruction Lab (CDL - Atlantic), a founding member of Canada’s Ocean Supercluster, a founding director at Endeavor Canada, and a mentor and investor in start-up companies. Mr. Huskilson is a member of the Association of Professional Engineers of Nova Scotia and serves on several not-for-profit boards of directors. Mr. Huskilson is Past-Chair of the Canadian Electricity Association, Past-Chair of the Greater Halifax Partnership, and Past-Chair of the Energy Council of Canada. He was a director of Emera Inc. until 2018 and a director of Tampa Electric until 2019. Mr. Huskilson is a member of the Nova Scotia Business Hall of Fame, a recipient of the Energy Person of the year, a recipient of the Catalyst Canada Award for advancement of women in the workplace and a recipient of the F.H. Sexton Gold Medal for Engineering. Mr. Huskilson holds a Bachelor of Science in Engineering, Master of Science in Engineering and Doctor of Science, Honoris Causa from the University of New Brunswick.	Director of AQN from October 27, 2009 to June 8, 2017, and since January 2, 2020 Trustee of APCo from July 20, 2009 until May 12, 2011
ANTHONY (JOHNNY) JOHNSTON Toronto, Ontario, Canada	Johnny Johnston is the Chief Operating Officer of AQN. Mr. Johnston has over 25 combined years of international experience in the regulated utility and renewable energy industries. Prior to joining the Corporation, Mr. Johnston, worked for National Grid where he led the transformation of its U.S. gas business. He has held a number of senior leadership roles in operations, customer service and strategy, working in both the U.K. and U.S. across gas and electric businesses. Mr. Johnston has served on the board of the not-for-profit Heartshare Human Services of New York. Mr. Johnston holds a Master of Engineering Science from the University of Oxford and a Master of Business Administration from the University of Cranfield. Mr. Johnston is a registered Chartered Engineer in the U.K.	Officer of AQN since January 8, 2019

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D. RANDY LANEY Farmington, Arkansas, USA	D. Randy Laney was most recently Chairman of the board of directors of Empire from 2009 until AQN’s acquisition of Empire on January 1, 2017. He joined the board of Empire in 2003 and served as the Non-Executive Vice Chairman from 2008 to 2009. Mr. Laney, semi-retired since 2008, has held numerous senior level positions with both public and private companies during his career, including 23 years with Wal-Mart Stores, Inc. in various executive positions such as Vice President of Finance, Benefits and Risk Management and Vice President of Finance and Treasurer. In addition, Mr. Laney has provided strategic advisory services to both private and public companies and served on numerous profit and non-profit boards. Mr. Laney brings significant management and capital markets experience, and strategic and operational understanding to his position on the Board. Mr. Laney holds a Bachelor of Science and a Juris Doctor from the University of Arkansas.	Director of AQN since February 1, 2017
KENNETH MOORE Toronto, Ontario, Canada	Kenneth Moore is the Managing Partner of NewPoint Capital Partners Inc., an investment banking firm. Mr. Moore holds the Chartered Financial Analyst designation and has completed the Chartered Director program of the Directors College (McMaster University) and holds the certification of Chartered Director.	Director of AQN since October 27, 2009 Trustee of APCo from November 12, 1998 until November 10, 2010
DARREN MYERS Toronto, Ontario Canada	Darren Myers is the Chief Financial Officer of AQN. Mr. Myers joined AQN in 2022 and has over 25 years of broad finance expertise, including public and capital markets experience in Canada and the U.S. Prior to joining AQN, Mr. Myers was Executive Vice President and Chief Financial Officer for Loblaw, Canada’s largest retailer. Mr. Myers also spent 16 years at Celestica, a global supply chain and manufacturing company. He was the Executive Vice President and Chief Financial Officer of Celestica from 2012 to 2017 and had responsibility for Global Business Services and IT. Mr. Myers holds a Bachelor of Commerce degree from McMaster University and is a Chartered Accountant.	Officer of AQN since August 31, 2022
JEFF NORMAN Burlington, Ontario, Canada	Jeff Norman is the Chief Development Officer of AQN, serving in this role since 2008. He was appointed to the AQN executive team in 2015. Mr. Norman co-founded the Algonquin Power Venture Fund in 2003 and served as President until it was acquired by APCo in 2008. Mr. Norman holds a Bachelor of Arts (Chartered Accountancy) and a Master of Accounting from the University of Waterloo.	Officer of AQN since May 25, 2015
KIRSTEN OLSEN Toronto, Ontario Canada	Kirsten Olsen is the Chief Human Resources Officer of AQN. Ms. Olsen joined AQN in 2019 and has over 20 years of international HR experience with expertise in supporting large-scale change, talent management and M&A. Prior to joining AQN, Kirsten held progressive HR leadership roles over the course of 12 years with GE in the UK. Ms. Olsen holds a Master of Industrial Relations & Human Resources from the University of Toronto and an Honours Bachelor of Arts with Distinction in Psychology from Huron College at the University of Western Ontario.	Officer of AQN since December 11, 2019
MARY ELLEN PARAVALOS Mississauga, Ontario, Canada	Mary Ellen Paravalos is the Chief Compliance and Risk Officer of AQN. Ms. Paravalos has over 20 years of international experience in the energy industry across operating, strategy and regulation & compliance areas. Prior to joining AQN, Ms. Paravalos was Vice President, ISO, Siting, and Compliance at Eversource Energy, and prior to that held a number of leadership roles at National Grid. Ms. Paravalos has served as a Director and President for the not-for-profit company New England Women in Energy and Environment. Ms. Paravalos holds a Master of Electric Power Engineering from Rensselaer Polytechnic Institute and a Bachelor of Electrical Engineering from Northeastern University. Ms. Paravalos is a registered engineer in the state of Massachusetts.	Officer of AQN since October 9, 2018
COLIN PENNY Midhurst, Ontario	Colin Penny is the Executive Vice President, Information Technology and Digital Transformation of AQN. Mr. Penny joined the Corporation in 2019 as the Vice President, Information Technology Transformation with over 20 years of experience delivering and operating technology solutions with a focus on business transformation and the strategic use of information and communication technologies within the energy and utilities sectors in North America. Prior to joining AQN, Mr. Penny was the Senior Vice President, Technology and Chief Information Officer of Hydro One Limited where he led the Information Solutions, Security and Telecom groups and before that spent the early part of his career with systems integration firms focused on control systems, cybersecurity, project delivery, and customer systems. Mr. Penny also cofounded and served as a Director for the Canadian Cyber Threat Exchange. Mr. Penny holds a Bachelor of Science (Honours) in Electrical Engineering from Queen’s University.	Officer of AQN since November 15, 2021

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MASHEED SAIDI Dana Point, California, United States	Masheed Saidi has over 30 years of operational and business leadership experience in the electric utility industry. Between 2010 and 2017, Ms. Saidi was an Executive Consultant with the Energy Initiatives Group, a specialized group of experienced professionals that provide technical, commercial and business consulting services to utilities, ISOs, government agencies and other organizations in the energy industry. Between 2005 and 2010, Ms. Saidi was the Chief Operating Officer and Executive Vice President of U.S. Transmission for National Grid USA, and she was responsible for all aspects of its U.S. transmission business. Ms. Saidi previously served as Chairperson of the board of directors for the non-profit organization Mary’s Shelter, and also previously served on the board of directors of the Northeast Energy and Commerce Association. She earned her Bachelor’s degree in Power System Engineering from Northeastern University and her Master of Electrical Engineering from the Massachusetts Institute of Technology. She is a Registered Professional Engineer in the state of Massachusetts.	Director of AQN since June 18, 2014
DILEK SAMIL Las Vegas, Nevada, United States	Dilek Samil has over 30 years of finance, operations and business experience in both the regulated energy utility sector as well as wholesale power production. Ms. Samil joined NV Energy as Chief Financial Officer and retired as Executive Vice President and Chief Operating Officer. While at NV Energy, Ms. Samil completed the financial transformation of the company, bringing its financial metrics in line with those of the industry. As Chief Operating Officer, Ms. Samil focused on enhancing the company’s safety and customer care culture. Prior to her role at NV Energy, Ms. Samil gained considerable experience in generation and system operations as President and Chief Operating Officer for CLECO Power. During her tenure at CLECO Power, the company completed construction of its largest generating unit and successfully completed its first rate case in over 10 years. Ms. Samil also served as CLECO Power’s Chief Financial Officer at a time when the industry and the company faced significant turmoil in the wholesale markets. She led the company’s efforts in the restructuring of its wholesale and power trading activities. Prior to NV Energy and CLECO Power, Ms. Samil spent close to 20 years at NextEra where she held positions of increasing responsibility, primarily in the finance area. Ms. Samil holds a Bachelor of Science from the City College of New York and a Master of Business Administration from the University of Florida.	Director of AQN since October 1, 2014
JENNIFER TINDALE Campbellville, Ontario, Canada	Jennifer Tindale is the Chief Legal Officer of AQN. Ms. Tindale has over 20 years of experience advising public companies on acquisitions, dispositions, mergers, financings, corporate governance and disclosure matters. From July 2011 to February 2017, Ms. Tindale was the Executive Vice President, General Counsel & Secretary at a cross-listed real estate investment trust. Prior to that, she was Vice President, Associate General Counsel & Corporate Secretary at a cross-listed pharmaceutical company and before that she was a partner at a top tier Toronto law firm, practising corporate securities law. Ms. Tindale holds a Bachelor of Arts and a Bachelor of Laws from the University of Western Ontario.	Officer of AQN since February 7, 2017

Each director will serve as a director of AQN until the next annual meeting of shareholders or until his or her successor is elected in accordance with the by-laws of AQN.

To the knowledge of the Corporation, as at March 16, 2023, the directors and executive officers of AQN, as a group, beneficially owned, directly or indirectly, or exercised control or direction over 832,939 Common Shares, representing less than 1% of the total number of issued and outstanding Common Shares before giving effect to the exercise of options to purchase Common Shares held by such directors and executive officers.

8.2Audit Committee

Pursuant to the by-laws of AQN, the Board has established an Audit Committee with the functions and responsibilities set out in its mandate. The Audit Committee is currently comprised of four directors of AQN: Ms. Samil (Chair), Ms. Barnes, Ms. Chande and Mr. Huskilson, all of whom are independent and financially literate for purposes of National Instrument 52-110 - Audit Committees. The Audit Committee is responsible for reviewing significant accounting, reporting and internal control matters, reviewing all published quarterly and annual financial statements and recommending their approval to the directors and assessing the performance of AQN’s auditors.

8.2.1Audit Committee Charter

The Audit Committee mandate is attached as Schedule A to this AIF.

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8.2.2Relevant Education and Experience

The following is a description of the education and experience, apart from their roles as directors of AQN, of each member of the Audit Committee that is relevant to the performance of their responsibilities as a member of the Audit Committee.

Ms. Samil has extensive financial experience, with over 30 years of finance, operations and business experience in the regulated energy utility sector. During her career, Ms. Samil was the Executive Vice President and Chief Operating Officer of NV Energy and gained considerable experience in generation and system operations as President and Chief Operating Officer for CLECO Power LLC. Ms. Samil holds a Bachelor of Science from the City College of New York and a Master of Business Administration from the University of Florida.

Ms. Barnes’ financial experience includes a number of risk management and legal/regulatory senior executive roles in a public company. Ms. Barnes was an executive officer and a member of the corporate executive committee of Eli-Lilly and Company. She has extensive experience in the areas of risk management, legal and regulatory and is a licensed attorney with the Indiana State Bar.

Ms. Chande’s financial experience includes a number of leadership and executive roles in large public and private companies. Ms. Chande was Chief Commercial Officer for Waymo, Google’s self-driving car project, a Managing Director at Alibaba Group and has held divisional Managing Director and Chief Executive Officer roles at global retailers including Tesco, Staples, and Wal-Mart in both Europe and the United States. Ms. Chande holds a Bachelor of Business Administration degree from Simon Fraser University, a Master of Science degree from the London School of Economics, and a Master of Business Administration from Harvard Business School.

Mr. Huskilson’s financial experience includes over 35 years in leadership and operational roles in the regulated utilities business in Canada, the United States and the Caribbean. Mr. Huskilson is the President and CEO of 5-H Holdings Inc. and Chair of XOCEAN Ltd. Mr. Huskilson was President and Chief Executive Officer of Emera Inc., from 2004 to 2018. Prior to that Mr. Huskilson held a number of positions within Nova Scotia Power Inc. and its predecessor, Nova Scotia Power Corporation, since June 1980. Mr. Huskilson holds a Bachelor of Science in Engineering and a Master of Science in Engineering from the University of New Brunswick.

8.2.3Pre-Approval Policies and Procedures

The Audit Committee has established a policy requiring pre-approval by the Audit Committee of all audit and permitted non-audit services provided to AQN by its external auditor. The Audit Committee may delegate pre-approval authority to a member of the Audit Committee; however, the decisions of any member of the Audit Committee to whom this authority has been delegated must be presented to the full Audit Committee at its next scheduled Audit Committee meeting.


Services	2022 Fees (C$)	2021 Fees (C$)
Audit Fees1	6,714,099		6,393,021
Audit-Related Fees2	95,500		101,458
Tax Fees3	630,204		552,786
All Other Fees4	50,000		50,000

1 For professional services rendered for audit or review or services in connection with statutory or regulatory filings or engagements.

2 For assurance and related services that are reasonably related to the performance of the audit or review of AQN’s financial statements and not

reported under Audit Fees, including audit procedures related to regulatory commission filings.

3 For tax advisory, compliance and planning services.

4 For all other products and services provided by AQN’s external auditor.

8.3Corporate Governance, Risk, and Human Resources and Compensation Committees

The Board has established a Corporate Governance Committee, currently comprised of four directors of AQN: Mr. Laney (Chair), Ms. Chande, Mr. Goldberg and Ms. Saidi.

The Board has established a Risk Committee, currently comprised of four directors of AQN: Ms. Saidi (Chair), Ms. Barnes, Mr. Huskilson and Ms. Samil.

The Board has also established a Human Resources and Compensation Committee, currently comprised of four directors of AQN: Ms. Barnes (Chair), Mr. Goldberg, Mr. Huskilson and Mr. Laney.

8.4Cease Trade Orders, Bankruptcies, Penalties or Sanctions

To the knowledge of AQN, no director or officer of AQN:

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a)is, as at the date of this AIF, or has been, within ten years before the date of this AIF, a director, chief executive officer or chief financial officer of any company that:

1.was subject to an Order that was issued while the director or officer was acting in the capacity as director, chief executive officer or chief financial officer; or

2.was subject to an Order that was issued after the director or officer ceased to be a director, chief executive officer or chief financial officer and which resulted from an event that occurred while that person was acting in the capacity as director, chief executive officer of chief financial officer;

b)is, as at the date of this AIF, or has been within ten years before the date of this AIF, a director or executive officer of any company that, while that person was acting in that capacity, or within a year of that person ceasing to act in that capacity, became bankrupt, made a proposal under any legislation relating to bankruptcy or insolvency or was subject to or instituted any proceedings, arrangements or compromise with creditors or had a receiver, receiver manager or trustee appointed to hold its assets;

c)has, within the ten years before the date of this AIF, become bankrupt, made a proposal under any legislation relating to bankruptcy or insolvency, or become subject to or instituted any proceedings, arrangement or compromise with creditors, or had a receiver, receiver manager or trustee appointed to hold the assets of the director or officer; or

d)has been subject to any penalties or sanctions imposed by a court relating to securities legislation or by a securities regulatory body or has entered in a settlement agreement with a securities regulatory body, or is subject to any penalties or sanctions imposed by a court or regulatory body that would likely be considered important to a reasonable investor making an investment decision.

8.5Conflicts of Interest

To the knowledge of the Corporation, there are no existing or potential material conflicts of interest between AQN or a subsidiary and any current director or officer of AQN or a subsidiary of AQN.

9.LEGAL PROCEEDINGS AND REGULATORY ACTIONS

9.1Legal Proceedings

The Corporation is not, and was not during the financial year ended December 31, 2022, party to any legal proceedings that involve a claim for damages equal to 10% or more of the current assets of the Corporation, and the Corporation is not aware of any such legal proceedings that are contemplated.

9.2Regulatory Actions

During the financial year ended December 31, 2022, there were:

a)no penalties or sanctions imposed against AQN by a court relating to securities legislation or by a securities regulatory authority;

b)no other penalties or sanctions imposed by a court or regulatory body against AQN that would likely be considered important to a reasonable investor in making an investment decision; and

c)no settlement agreements that AQN has entered into with a court relating to securities legislation or with a securities regulatory authority.

10.INTEREST OF MANAGEMENT AND OTHERS IN MATERIAL TRANSACTIONS

No director, executive officer or 10% holder of voting securities, or any associate or affiliate of the foregoing has, or has had, any material interest in any transaction within the three most recently completed financial years or during the current financial year that has materially affected or will materially affect AQN or any of its affiliates.

11.TRANSFER AGENTS AND REGISTRARS

The transfer agent and registrar for the Common Shares, the Series A Shares and the Series D Shares listed on the TSX is TSX Trust Company, at its offices in Toronto, Ontario.

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The transfer agent and registrar for the Common Shares listed on the NYSE is American Stock Transfer & Trust Company, LLC, at its office in Brooklyn, New York.

12.MATERIAL CONTRACTS

The Corporation does not have any material contracts that were not entered into in the ordinary course of business of the Corporation other than:

1.Stock Purchase Agreement dated October 26, 2021 between Liberty Utilities and the Sellers with respect to the Kentucky Power Transaction (the “Kentucky Acquisition Agreement”), as amended by the first amendment to stock purchase agreement dated September 29, 2022 and by the second amendment to stock purchase agreement dated January 16, 2023.

The aggregate purchase price for the Kentucky Power Transaction was initially approximately $2.846 billion, comprised of a cash purchase price of approximately $1.625 billion and the assumption of approximately $1.221 billion in debt, subject to customary closing adjustments. On September 29, 2022, the parties entered into an amendment to the Kentucky Acquisition Agreement that, among other things, reduced the purchase price by $200 million to approximately $2.646 billion, including the assumption of approximately $1.221 billion in debt. On January 16, 2023, the parties entered into a further amendment to the Kentucky Acquisition Agreement in order to clarify the parties’ understanding and agreement with respect to seeking approval for the Kentucky Power Transaction from FERC. Closing of the Kentucky Power Transaction is subject to receipt or waiver of certain regulatory and governmental approvals, including the approval of FERC and clearance under the Hart-Scott-Rodino Antitrust Improvements Act of 1976 (as the clearance received previously has lapsed), and the satisfaction of other customary closing conditions. If the Kentucky Power Transaction has not closed by April 26 2023, either party may have the option to terminate the Kentucky Acquisition Agreement in accordance with its terms. The Corporation is subject to a “no burdensome condition” standard to obtain the required regulatory and governmental approvals, provided that the Corporation is not required to agree to any conditions that would have a material adverse effect on Kentucky Power and Kentucky TransCo as a whole. The Kentucky Acquisition Agreement contains representations, warranties, covenants, indemnities, conditions and termination rights typical of those contained in business acquisition agreements negotiated between sophisticated purchasers and vendors acting at arm’s length. The representations and warranties shall not survive the completion of the Kentucky Power Transaction, but the Corporation has obtained representation and warranty insurance coverage, which is subject to customary limitations and conditions. In addition, if the Kentucky Acquisition Agreement is terminated in certain circumstances, the Corporation may be required to pay to the Sellers a termination fee of $65 million.

13. EXPERTS

Ernst & Young LLP is the external auditor of the Corporation and has confirmed that it is (i) independent with respect to the Corporation within the meaning of the CPA Code of Professional Conduct of the Chartered Professional Accountants of Ontario and (ii) an independent registered public accounting firm with respect to the Corporation within the meaning of the U.S. Securities Act of 1933, the applicable rules and regulations adopted thereunder by the SEC and the Public Company Accounting Oversight Board (United States).

14. ADDITIONAL INFORMATION

Additional information relating to AQN may be found on SEDAR at www.sedar.com. Additional information, including disclosure regarding directors’ and officers’ remuneration and indebtedness, principal holders of AQN’s securities and securities authorized for issuance under equity compensation plans is contained in AQN’s information circular for its most recent annual meeting. Additional financial information is provided in AQN’s financial statements and MD&A for the fiscal year ended December 31, 2022, which are available on SEDAR at www.sedar.com and on EDGAR at www.sec.gov/edgar.

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SCHEDULE A

ALGONQUIN POWER & UTILITIES CORP.

MANDATE OF THE AUDIT COMMITTEE

By resolution of the board of directors (the “Board”) of Algonquin Power & Utilities Corp., the Audit Committee (the “Committee”) has been established as a standing committee of the Board with the terms of reference set forth below. Unless the context requires otherwise, “Corporation” refers to Algonquin Power & Utilities Corp. and its subsidiaries.

1.PURPOSE

1.1The Committee’s primary purposes are to:

a)assist the Board’s oversight of:

(i)the integrity of the Corporation’s financial statements, Management’s Discussion and Analysis (“MD&A”), earnings releases or news releases containing earnings guidance and other financial reporting;

(ii)the Corporation’s compliance with legal and regulatory requirements in connection with its financial statements, MD&A, earnings releases or news releases containing earnings guidance and other financial reporting;

(iii)the external auditor’s qualifications, independence and performance;

(iv)the performance of the Corporation’s internal audit function and internal auditor;

(v)the communication among management of the Corporation (“Management”), the external auditor, the internal auditor, and the Board; and

(vi)Management’s strategies for tax planning; and

b)review and approve, or recommend the Board’s approval of (as applicable), any report that is required by law or regulation to be included in any of the Corporation’s public disclosure documents relating to the matters contained in this Mandate.

2.COMMITTEE MEMBERSHIP

2.1Number of Members – The Committee shall consist of not fewer than three members.

2.2Independence of Members – Each member of the Committee shall:

a)be a director of the Corporation;

b)not be an officer or employee of the Corporation or any of the Corporation’s subsidiary entities or affiliates; and

c)be independent as determined in accordance with sections 1.4 and 1.5 of National Instrument 52-110 (“NI 52-110”) and other applicable laws and regulations, including the standards of The New York Stock Exchange and Section 10A-3 of the U.S. Securities Exchange Act of 1934.

2.3Financial Literacy – Each member of the Committee shall satisfy the financial literacy requirements applicable to members of audit committees under NI 52-110 and other applicable laws and regulations. At least one member of the Committee shall be a “financial expert” within the meaning of item 407(d) of Regulation S-K under the U.S. Securities Act of 1933.

2.4Chair – The Chair of the Committee shall be selected from among the members of the Committee.

2.5Annual Appointment of Members – The Committee and its Chair shall be appointed annually by the Chair of the Board and each member of the Committee shall serve at the pleasure of the Chair of the Board or until he or she resigns, is removed or ceases to be a director.

3.COMMITTEE MEETINGS

3.1Meetings – The time and place of the meetings of the Committee and the procedure in all things at such meetings shall be determined by the Committee. A meeting of the Committee may be called by any member of the Committee or by the external auditor. The Committee shall meet as frequently as necessary to carry out its duties and responsibilities, but not less than four times annually. A majority of members of the Committee shall constitute a quorum and the Committee shall maintain minutes or other records of its meetings and activities.

3.2Access to Management – The Committee shall have unrestricted access to Management and the external auditor.

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3.3Meetings Without Management – At each meeting of the Committee it will meet for a portion of the meeting without Management present, and the Committee shall also hold in camera sessions with representatives of the external auditor, internal audit personnel, and such other members of Management as the Committee requests.

4.COMMITTEE AUTHORITY

4.1Advisors – The Committee may retain, at the expense of the Corporation, such outside legal, accounting (other than the external auditor) or other advisors on such terms as the Committee may consider appropriate and shall not be required to obtain any other approval in order to retain or compensate any such advisors.

4.2Funding – The Corporation shall provide for appropriate funding, as determined by the Committee, for payment of compensation of the external auditor and any advisor retained by the Committee under Section 4.1 of this Mandate, and for the payment of the ordinary administrative expenses of the Committee that are necessary or appropriate in carrying out its duties.

4.3Access to Records – The Committee shall have unrestricted access to the documents and records of the Corporation and shall be provided with the resources necessary to carry out its responsibilities.

5.DUTIES AND RESPONSIBILITIES OF THE COMMITTEE

5.1Overview – The Committee’s principal responsibility is one of oversight. Management is responsible for preparing the Corporation’s financial statements and the external auditor is responsible for auditing those financial statements.

The Committee’s specific duties and responsibilities are as follows:

a)Financial and Related Information –

(i)Financial Statements – The Committee shall review and discuss with Management and the external auditor the Corporation’s annual and quarterly financial statements and related MD&A and earnings release and report thereon to the Board before the Board approves such statements, MD&A and earnings release.

(ii)Prospectuses and Other Documents – The Committee shall review and discuss with Management and the external auditor the financial information, financial statements and related MD&A appearing in any prospectus, annual report, annual information form (including Form 40-F), management information circular, news releases containing earnings guidance or any other public disclosure document prior to its public release or filing.

(iii)Accounting Treatment – Prior to the completion of the annual external audit, and at any other time considered advisable by the Committee, the Committee shall review and discuss with Management and the external auditor the quality and not just the acceptability of the Corporation’s accounting principles and financial statement presentation, including the following:

A)all critical accounting policies and practices to be used, including the reasons why certain estimates or policies are or are not considered critical and how current and anticipated future events impact those determinations and an assessment of Management’s disclosures along with any significant proposed modifications by the external auditor that were not included;

B)all alternative treatments within generally accepted accounting principles for policies and practices related to material items that have been discussed with Management, including ramifications of the use of such alternative disclosure and treatments and the treatment preferred by the external auditor, which discussion should address recognition, measurement, and disclosure considerations related to the accounting for specific transactions as well as general accounting policies. Communications regarding specific transactions should identify the underlying facts, financial statement accounts affected, and applicability of existing corporate accounting policies to the transaction. Communications regarding general accounting policies should focus on the initial selection of, and changes in, significant accounting policies, the effect of Management’s judgments and accounting estimates, and the external auditor’s judgments about the quality of the Corporation’s accounting principles. Communications regarding specific transactions and general accounting policies should include the range of alternatives available under generally accepted accounting principles discussed by Management and the external auditor and the reasons for selecting the chosen treatment or policy. If the external auditor’s preferred accounting treatment or accounting policy is not selected, the reasons therefor should also be reported to the Committee;

C)other material written communications between the external auditor and Management, such as any management letter, schedule of unadjusted differences,

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listing of adjustments and reclassifications not recorded, management representation letter, report on observations, recommendations on internal controls, engagement letter, and independence letter;

D)major issues regarding financial statement presentations;

E)any significant changes in the Corporation’s selection or application of accounting principles;

F)the effect of regulatory and accounting initiatives and off balance sheet structures on the financial statements of the Corporation; and

G)the adequacy of the Corporation’s internal controls and any special audit steps adopted in light of control deficiencies.

(iv)Disclosure of Other Financial Information – The Committee shall:

A)review and discuss with Management the type and presentation of information to be included in all public disclosure by the Corporation containing audited, unaudited or forward-looking financial information in advance of its public release by the Corporation, including earnings guidance and financial information based on unreleased financial statements;

B)discuss with Management the type and presentation of information to be included in earnings and any other financial information given to analysts and rating agencies, if any; and

C)satisfy itself that adequate procedures are in place for the review of the Corporation’s disclosure of financial information extracted or derived from the Corporation’s financial statements, other than the Corporation’s financial statements, MD&A and earnings press releases, and periodically assess the adequacy of those procedures.

b)External Auditor –

(i)Authority with Respect to External Auditor – The Committee shall be directly responsible for the appointment, compensation, retention, termination, and oversight of the work of the external auditor (including resolution of disagreements between Management and the external auditor regarding financial reporting) for the purpose of preparing or issuing an audit report or performing other audit, review or attestation services for the Corporation. The Committee shall have sole authority for recommending the person to be proposed to the Corporation’s shareholders for appointment as external auditor, for determining whether at any time the incumbent external auditor should be removed from office, and for determining the compensation of the external auditor. The Committee shall require the external auditor to confirm in an engagement letter to the Committee each year that the external auditor is accountable to the Board and the Committee as representatives of shareholders and that it will report directly to the Committee.

(ii)Approval of Audit Plan – The Committee shall approve, prior to the external auditor’s audit, the external auditor’s audit plan (including staffing levels), the scope of the external auditor’s review, and all related fees.

(iii)Independence – The Committee shall satisfy itself as to the independence of the external auditor. As part of this process:

A)The Committee shall require the external auditor to submit on a periodic basis to the Committee a formal written statement confirming its independence under applicable laws and regulations and delineating all relationships between the external auditor and the Corporation and the Committee shall actively engage in a dialogue with the external auditor with respect to any disclosed relationships or services that may affect the objectivity or independence of the external auditor and take or, if applicable, recommend that the Board take, any action the Committee considers appropriate in response to such report to satisfy itself of the external auditor’s independence.

B)In accordance with applicable laws and regulations, the Committee shall pre–approve any non–audit services (including fees therefor) provided to the Corporation by the external auditor or any auditor of any subsidiary and shall consider whether these services are compatible with the external auditor’s independence, including the nature and scope of the specific non–audit services to be performed and whether the audit process would require the external auditor to review any advice rendered by the external auditor in connection with the provision of non-audit services. The Committee may delegate to one or more

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designated members of the Committee the authority to approve additional non-audit services that arise between Committee meetings, provided that such designated members report any such approvals to the Committee at its next meeting.

C)The Committee shall establish a policy setting out the restrictions on the Corporation’s subsidiary entities hiring partners, employees, former partners and former employees of the external auditor or former external auditor.

(iv)Rotating of Auditor Partner – The Committee shall evaluate the performance of the external auditor and whether it is appropriate to adopt a policy of rotating lead or responsible partners of the external auditor.

(v)Review of Audit Problems and Internal Audit – The Committee shall review with the external auditor:

A)any problems or difficulties the external auditor may have encountered, including any restrictions on the scope of activities or access to required information, and any disagreements with Management and any management letter provided by the auditor and the Corporation’s response to that letter;

B)any changes required in the planned scope of the internal audit; and

C)the internal audit department’s responsibilities, budget and staffing.

(vi)Review of Proposed Audit and Accounting Changes – The Committee shall review major changes to the Corporation’s auditing and accounting principles and practices suggested by the external auditor.

(vii)Regulatory Matters – The Committee shall discuss with the external auditor the matters required to be discussed by Section 5741 of the CICA Handbook – Assurance relating to the conduct of the audit.

c)Internal Audit Function – Controls –

(i)Regular Reporting – Internal audit personnel shall report regularly to the Committee.

(ii)Oversight of Internal Controls – The Committee shall oversee Management’s design and implementation of and reporting on the Corporation’s internal controls and review the adequacy and effectiveness of Management’s financial information systems and internal controls. The Committee shall periodically review and approve the mandate, plan, budget, and staffing of the internal audit department. The Committee shall direct Management to make any changes it deems advisable in respect of the internal audit function.

(iii)Review of Audit Problems – The Committee shall review with internal audit personnel any problem or difficulties internal audit personnel may have encountered, including any restrictions on the scope of activities or access to required information, and any significant reports to Management prepared by internal audit personnel and Management’s responses thereto.

(iv)Review of Internal Audit Personnel – The Committee shall review the appointment, performance, and replacement of the senior internal audit personnel and the activities, organization structure, and qualifications of the persons responsible for the internal audit function.

d)Risk Assessment and Risk Management –

(i)Risk Exposure – The Committee shall discuss periodically with the external auditor, internal audit personnel, and Management the Corporation’s major financial risk exposures and the steps Management has taken to monitor and control such exposures.

(ii)Investment Practices – The Committee shall review Management’s plans and strategies around investment practices and treasury risk management.

(iii)Compliance with Covenants – The Committee shall review Management’s procedures to assess compliance by the Corporation with its loan covenants and restrictions, if any.

e)Taxation – The Committee shall review on a periodic basis Management’s tax planning strategies, tax planning structures, and associated matters.

f)Whistle-Blowing – The Committee shall establish procedures for:

(i)the receipt, retention, and treatment of complaints received by the Corporation regarding accounting, internal accounting controls or auditing matters; and

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(ii)the confidential, anonymous submission by the Corporation’s employees of concerns regarding questionable accounting or auditing matters.

g)Review of Management’s Certifications and Reports – The Committee shall review and discuss with Management all certifications of financial information, management reports on internal controls, and all other management certifications and reports relating to the Corporation’s financial position or operations required to be filed or released under applicable laws and regulations prior to the filing or release of such certifications or reports.

h)Liaison – The Committee shall assess whether appropriate liaison and co–operation exist between the external auditor and internal audit personnel and provide a direct channel of communication between the external auditor, internal auditors, and the Committee.

i)Public Reports – The Committee shall review and approve, or recommend the Board’s approval of (as applicable), any report that is required by law or regulation to be included in any of the Corporation’s public disclosure documents relating to the matters contained in this Mandate.

j)Other Matters – The Committee may, in addition to the foregoing, perform such other functions as may be necessary or appropriate for the performance of its duties and responsibilities.

6.REPORTING TO THE BOARD

6.1Regular Reporting – The Committee shall report to the Board on its activities following each meeting of the Committee and at such other times as the Committee may determine to be appropriate.

7.EVALUATION OF COMMITTEE PERFORMANCE

7.1Performance Review – The Committee shall periodically assess its performance and that of its Chair.

7.2Amendments to Mandate – The Committee shall periodically review and discuss the adequacy of this Mandate and, if applicable, recommend any proposed changes to the Board for approval.

8.CURRENCY OF MANDATE

8.1Currency of Mandate – This Mandate is effective as of March 16, 2023.

B - 1

SCHEDULE B

GLOSSARY OF TERMS

In this AIF, the following terms have the meanings set forth below, unless otherwise indicated:

“2018 Notes Interest Reset Date” has the meaning ascribed thereto under “Description of Capital Structure – Subordinated Notes”.

“2018 Subordinated Notes” has the meaning ascribed thereto under “Description of Capital Structure – Preferred Shares”.

“2019 Notes Interest Reset Date” has the meaning ascribed thereto under “Description of Capital Structure – Subordinated Notes”.

“2019 Subordinated Notes” has the meaning ascribed thereto under “Description of Capital Structure – Preferred Shares – Series G Shares”.

“2021 Bought Deal Offering” has the meaning ascribed thereto under “General Development of the Business – Three Year History – Fiscal 2021 – Corporate”.

“2022 Asset Recycling Transaction” has the meaning ascribed thereto under “General Development of the Business – Three Year History – Fiscal 2022 – Renewable Energy Group”.

“2022 Subordinated Note Offering” has the meaning ascribed thereto under “General Development of the Business – Three Year History – Fiscal 2022 – Corporate”

“2022-A Interest Payment Date” has the meaning ascribed thereto under “Description of Capital Structure – Subordinated Notes”.

“2022-A Notes Interest Reset Date” has the meaning ascribed thereto under “Description of Capital Structure – Subordinated Notes”.

“2022-A Subordinated Notes” has the meaning ascribed thereto under “General Development of the Business – Three Year History – Fiscal 2022 – Corporate”.

“2022-B Notes Interest Reset Date” has the meaning ascribed thereto under “Description of Capital Structure – Subordinated Notes”.

“2022-B Subordinated Notes” has the meaning ascribed thereto under “General Development of the Business – Three Year History – Fiscal 2022 – Corporate”.

“5-Year Government of Canada Yield” has the meaning ascribed thereto in the first supplemental indenture dated as of January 18, 2021 between AQN and TSX Trust Company providing for the issue of the 2022-A Subordinated Notes.

“AIF” means this annual information form.

“Altavista Solar Facility” means the 80 MW Altavista solar generation facility in Campbell County, Virginia

“Amended and Restated Rights Plan” has the meaning ascribed thereto under “Description of Capital Structure – Shareholders’ Rights Plan”.

“Amherst Island Wind Facility” means the approximately 74 MW Amherst Island wind energy facility located in Ontario on Amherst Island near the village of Stella.

“APCo” has the meaning ascribed thereto under “Corporate Structure – Name, Address and Incorporation”.

“APSC” means Arkansas Public Services Commission.

“AQN” has the meaning ascribed thereto under “Corporate Structure – Name, Address and Incorporation”.

“Atlantica” has the meaning ascribed thereto under “General Development of the Business – Renewable Energy Group”.

“Atlantica Strategic Review” has the meaning ascribed thereto under “Enterprise Risk Factors – Risk Factors Relating to Strategic Planning and Execution”.

“AY Holdings” has the meaning ascribed thereto under “Corporate Structure – Intercorporate Relationships”.

“Bakersfield I Solar Facility” means the 20 MW Bakersfield solar generating facility in California.

“BELCO” has the meaning ascribed thereto under “General Development of the Business – Three Year History – Fiscal 2020 – Corporate”.

“Blue Hill Wind Facility” means the 175 MW Blue Hill wind energy facility in Saskatchewan.

“Board” means the Algonquin Power & Utilities Corp. board of directors.

B - 2

“BRRBA” means base revenue requirement balancing account.

“CalPeco Electric System” means an electricity distribution utility in the Lake Tahoe basin and surrounding areas.

“CCRs” has the meaning ascribed thereto under “Enterprise Risk Factors – Risk Factors Relating to Regulatory Environment”.

“CDOR” means the Canadian Dollar Offered Rate.

“Chevron” means Chevron U.S.A. Inc.

“Collateral Reset Level” has the meaning ascribed thereto under “Enterprise Risk Factors – Risk Factors Relating to Strategic Planning and Execution”.

“Common Shares” means the common shares of Algonquin Power & Utilities Corp.

“Corporation” has the meaning ascribed thereto under “Corporate Structure – Name, Address and Incorporation”.

“COVID-19” means the 2019 novel coronavirus.

“CPUC” means California Public Utilities Commission.

“DBRS” means the credit rating agency Dominion Bond Rating Service Limited.

“Deerfield Wind Facility” means the 149 MW Deerfield wind energy facility in Michigan.

“EBITDA” means earnings before interest, taxes, depreciation and amortization.

“EDG” has the meaning ascribed thereto under “Corporate Structure – Intercorporate Relationships”.

“Empire” has the meaning ascribed thereto under “Corporate Structure – Intercorporate Relationships”.

“Empire District Electric System” means an electricity distribution and generation utility in Missouri, Kansas, Oklahoma and Arkansas.

“Energy Service” has the meaning ascribed thereto under “Description of the Business – Regulated Services Group – Electric Distribution Systems – Selected Facilities”.

“EnergyNorth Gas System” means a natural gas distribution utility in New Hampshire.

“EPC” means engineering, procurement and construction.

“Equity Unit Offering” has the meaning ascribed thereto under “General Development of the Business – Three Year History – Fiscal 2021 – Corporate”.

“Equity Units” has the meaning ascribed thereto under “General Development of the Business – Three Year History – Fiscal 2021 – Corporate”.

“ERCOT” means Electric Reliability Council of Texas.

“ERM” means enterprise risk management.

“ESSAL” has the meaning ascribed thereto under “General Development of the Business – Three Year History – Fiscal 2020 – Regulated Services Group”.

“FERC” means the Federal Energy Regulatory Commission.

“FIT” means feed-in tariff.

“Fitch” means Fitch Ratings, Inc.

“Five-Year U.S. Treasury Rate” has the meaning ascribed thereto in the third supplemental indenture dated as of January 18, 2082 among AQN, American Stock Transfer & Trust Company, LLC and TSX Trust Company providing for the issue of the 2022-B Subordinated Notes.

“GAAP” means Generally Accepted Accounting Principles.

“GAF” has the meaning ascribed thereto under “Description of the Business – Regulated Services Group – Description of Operations – Natural Gas Distribution Systems – Selected Facilities”.

“Granite State Electric System” means an electricity distribution utility in New Hampshire.

“Great Bay I Solar Facility” means the 75 MW Great Bay I solar facility in Somerset County, Maryland.

“Great Bay II Solar Facility” means the 43 MW Great Bay II solar facility in Somerset County, Maryland.

“GW” means gigawatt.

“IESO” means Independent Electricity System Operator for Ontario.

“ISO” means independent system operator.

B - 3

“ISO-NE” means Independent System Operator New England.

“KCC” means State Corporation Commission of the State of Kansas.

“Kentucky Acquisition Agreement” has the meaning ascribed thereto under “Material Contracts”.

“Kentucky Power” has the meaning ascribed thereto under “General Development of the Business – Three Year History – Fiscal 2021 – Regulated Services Group”.

“Kentucky Power Transaction” has the meaning ascribed thereto under “General Development of the Business – Three Year History – Fiscal 2021 – Regulated Services Group”.

“Kentucky TransCo” has the meaning ascribed thereto under “General Development of the Business – Three Year History – Fiscal 2021 – Regulated Services Group”.

“Kings Point Wind Facility” means the approximately 150 MW wind facility located in Barton County, southwestern Dade County, northeastern Jasper County, and northwestern Lawrence County, Missouri.

“kV” means kilovolt.

“Liberty Apple Valley Water” has the meaning ascribed thereto under “Description of the Business – Regulated Services Group – Description of Operations – Water Distribution and Wastewater Collection Systems”.

“Liberty JV” means the joint venture between the Corporation and funds managed by the Infrastructure and Power strategy of Ares Management LLC.

“Liberty JV Secured Credit Facility” has the meaning ascribed thereto under “Enterprise Risk Factors – Risk Factors Relating to Strategic Planning and Execution”.

“Liberty New York Water” has the meaning ascribed thereto under “General Development of the Business – Three Year History – Fiscal 2020 – Regulated Services Group”.

“Liberty Park Water” has the meaning ascribed thereto under “Description of the – Business Regulated Services Group – Description of Operations – Water Distribution and Wastewater Collection Systems”.

“Liberty Utilities” has the meaning ascribed thereto under “Corporate Structure – Intercorporate Relationships”.

“Liberty Utilities Canada” has the meaning ascribed thereto under “Corporate Structure – Intercorporate Relationships”.

“LIBOR” has the meaning ascribed thereto in the first supplemental indenture dated as of October 17, 2018 between AQN, American Stock Transfer & Trust Company, LLC and TSX Trust Company (as successor to AST Trust Company (Canada)) providing for the issue of the 2018 Subordinated Notes and in the second supplemental indenture dated as of May 23, 2019 between AQN, American Stock Transfer & Trust Company, LLC and TSX Trust Company (as successor to AST Trust Company (Canada)) providing for the issue of the 2019 Subordinated Notes.

“Litchfield Park Water System” means the Litchfield Park water and wastewater system in Arizona.

“Luning Solar Facility” means the 50 MW solar generating facility located in Mineral County, Nevada.

“Manitoba Hydro” means the Manitoba Hydro-Electric Board.

“Maverick Creek Wind Facility” means the approximately 492 MW Maverick Creek wind facility in Concho County, Texas.

“MD&A” has the meaning ascribed thereto under “Caution Concerning Forward-looking Statements and Forward-looking Information”.

“MDPU” means The Massachusetts Department of Public Utilities.

“Midstates Gas Systems” means natural gas distribution utility assets in Missouri, Iowa and Illinois.

“Minonk Wind Facility” means the Minonk wind energy facility in Illinois.

“MISO” means Midcontinent Independent System Operator, Inc.

“Mitchell Plant” means has the meaning ascribed thereto under “General Development of the Business – Three Year History – Fiscal 2021 – Regulated Services Group”.

“Moody’s” means Moody’s Investors Services, Inc.

“MPSC” means Missouri Public Service Commission.

“MW” means megawatt.

“NB Energy Board” means the New Brunswick Energy and Utilities Board.

“Neosho Ridge Wind Facility” means the approximately 300 MW wind facility located in Neosho County, Kansas.

“NERC” means the North American Electric Reliability Corporation.

“New Brunswick Gas System” means the natural gas distribution utility assets in New Brunswick.

B - 4

“New England Gas System” means natural gas distribution utility assets in Massachusetts.

“New York Water System” means a water and wastewater utility system in New York.

“NHPUC” means the New Hampshire Public Utilities Commission.

“North Fork Ridge Wind Facility” means the approximately 150 MW wind facility located in northwestern Jasper County and southwestern Barton County, Missouri.

“NV Energy” means NV Energy, Inc.

“NYSE” means New York Stock Exchange.

“OATT” means open access transmission tariff.

“OCC” means Corporation Commission of Oklahoma.

“Odell Wind Facility” means the 200 MW Odell wind facility in Cottonwood, Jackson, Martina and Watonwan counties in Minnesota.

“OECD” has the meaning ascribed thereto under “Enterprise Risk Factors – Risk Factors Relating to Financing and Financial Reporting”.

“Offtake Contract” has the meaning ascribed thereto under “Enterprise Risk Factors – Risk Factors Relating to Strategic Planning and Execution”.

“OPEB” has the meaning ascribed thereto under “Enterprise Risk Factors – Risk Factors Relating to Financing and Financial Reporting”.

“Order” means (a) a cease trade order; (b) an order similar to a cease trade order; or (c) an order that denied the relevant company access to any exemption under securities legislation, that was in effect for a period of more than 30 consecutive days.

“Par Call Period” has the meaning ascribed thereto under “Description of Capital Structure – Subordinated Notes”.

“Peach State Gas System” means natural gas distribution utility assets in Georgia.

“PGA” means purchased gas adjustment.

“PJM” means PJM Interconnection, L.L.C.

“PPA” means power purchase agreement.

“Primary Energy Production Hedge” has the meaning ascribed thereto under “Description of the Business – Renewable Energy Group – Description of Operations – Wind Power Generating Facilities – Selected United States Facilities”.

“RAB” means the Regulatory Authority of Bermuda.

“REC” means renewable energy credit.

“Reinvestment Plan” has the meaning ascribed thereto under “General Development of the Business – Three Year History – Fiscal 2023 – Corporate”.

“RNG” means renewable natural gas.

“RWE Renewables” means RWE Renewables Americas, LLC.

“RTO” means regional transmission organization.

“S&P” means Standard & Poor’s Financial Services LLC.

“Sandhill” has the meaning ascribed thereto under “General Development of the Business – Three Year History – Fiscal 2022 – Renewable Energy Group”.

“Sandy Ridge Wind Facility” means the Sandy Ridge wind energy facility in Texas.

“SaskPower” means Saskatchewan Power Corporation.

“SEC” means U.S. Securities and Exchange Commission.

“Sellers” has the meaning ascribed thereto under “General Development of the Business – Three Year History – Fiscal 2021 – Regulated Services Group”.

“Senate Wind Facility” means the Senate wind energy facility in Texas.

“Series A Shares” has the meaning ascribed thereto under “Dividends – Preferred Shares”.

“Series A Shares Redemption Right” has the meaning ascribed thereto under “Description of Capital Structure – Preferred Shares”.

B - 5

“Series B Shares” has the meaning ascribed thereto under “Description of Capital Structure – Preferred Shares”.

“Series C Shares” has the meaning ascribed thereto under “Dividends – Preferred Shares”.

“Series D Shares” has the meaning ascribed thereto under “Dividends – Preferred Shares”.

“Series D Shares Redemption Right” has the meaning ascribed thereto under “Description of Capital Structure – Preferred Shares”.

“Series E Shares” has the meaning ascribed thereto under “Description of Capital Structure – Preferred Shares”.

“Series F Shares” has the meaning ascribed thereto under “Description of Capital Structure – Preferred Shares”.

“Series G Shares” has the meaning ascribed thereto under “Description of Capital Structure – Preferred Shares – Series G Shares”.

“Series H Shares” has the meaning ascribed thereto under “General Development of the Business – Three Year History – Fiscal 2022 – Corporate”.

“Series I Shares” has the meaning ascribed thereto under “General Development of the Business – Three Year History – Fiscal 2022 – Corporate”.

“Shady Oaks Wind Facility” means the Shady Oaks wind energy facility in Illinois.

“SPP” means Southwest Power Pool.

“St. Lawrence Gas System” means natural gas distribution utility assets in northern New York State.

“St. Leon LP” has the meaning ascribed thereto under “Corporate Structure – Intercorporate Relationships”.

“St. Leon Wind Facility” means the approximately 120 MW wind facility located at St. Leon, Manitoba.

“Sugar Creek Wind Facility” means the 202 MW Sugar Creek wind facility in Logan County, Illinois.

“TCFD” has the meaning ascribed thereto under “Description of the Business – Social and Environmental Policies and Commitment to Sustainability – ESG Report and Climate Change Assessment Report”.

“Texas Coastal Wind Facilities” has the meaning ascribed thereto under “General Development of the Business – Three Year History – Fiscal 2020 – Regulated Services Group”.

“Tinker Hydro Facility” means the electric generating facility and transmission assets in New Brunswick.

“TSX” means the Toronto Stock Exchange.

“Turquoise Solar Facility” means the 10 MW solar generating facility located in Washoe County, Nevada.

“U.S. Exchange Act” has the meaning ascribed thereto under “Enterprise Risk Factors – Risk Factors Relating to Financing and Financial Reporting”.

“Windsor Locks Thermal Facility” has the meaning ascribed thereto under the heading “Description of the Business – Renewable Energy Group – Description of Operations – Thermal (Cogeneration) Electric Generating Facilities – Selected Facilities”.

Consolidated Financial Statements of

Algonquin Power & Utilities Corp.

For the years ended December 31, 2022 and 2021

MANAGEMENT’S REPORT

Financial Reporting

The accompanying consolidated financial statements and management discussion and analysis (“MD&A”) are the responsibility of management and have been approved by the Board of Directors.

The consolidated financial statements have been prepared by management in accordance with U.S. generally accepted accounting principles. Financial statements by nature include amounts based upon estimates and judgments. When alternative accounting methods exist, management has chosen those it deems most appropriate in the circumstances.

The Board of Directors and its committees are responsible for all aspects related to governance of the Company. The Audit Committee of the Board of Directors, composed of directors who are unrelated and independent, has a specific responsibility to oversee management’s efforts to fulfill its responsibilities for financial reporting and internal controls related thereto. The Committee meets with management and independent auditors to review the consolidated financial statements and the internal controls as they relate to financial reporting. The Audit Committee reports its findings to the Board of Directors for its consideration in approving the consolidated financial statements for issuance to the shareholders.

Internal Control over Financial Reporting

Management is also responsible for establishing and maintaining adequate internal control over financial reporting. The Company’s internal control over financial reporting is a process designed to provide reasonable assurance regarding the reliability of financial reporting and the preparation of consolidated financial statements for external purposes in accordance with generally accepted accounting principles.

The Company acquired New York American Water Company, Inc (subsequently renamed Liberty Utilities (New York Water) Corp. (“Liberty NY Water”)) effective January 1, 2022. The financial information for this acquisition is included in the MD&A and in Note 3 to the consolidated financial statements. Liberty NY Water contributed $125,370 in revenue and $21,776 operating income, representing approximately 5% and 4% of the Company's consolidated revenue and operating income, respectively, for the year ended December 31, 2022. Liberty NY Water represented approximately 4% of the Company's total consolidated assets, and 3% of the Company's total consolidated liabilities, respectively, as of December 31, 2022. National Instrument 52-109 and the U.S. Securities and Exchange Commission provide an exemption whereby companies undergoing acquisitions can exclude the acquired business in the year of acquisition from the scope of testing and assessment of design and operational effectiveness of controls over financial reporting. Due to the complexity associated with assessing internal controls during integration efforts, the Company has utilized the scope exemption as it relates to this acquisition in its conclusion on internal controls over financial reporting for the year ending December 31, 2022.

During the fiscal quarter ended December 31, 2022, there was a material change to the Company’s internal controls over financial reporting, as the Company updated certain of its technology infrastructure systems through the implementation of an integrated customer solution platform, customer billing, and enterprise resource planning systems across core business processes for the Company’s East Region regulated entities and processes in the corporate function. This change to the Company’s internal controls included an assessment of the necessary and appropriate processes and controls with a view to ensuring that the design and operation of controls remains effective over financial reporting.

Management assessed the effectiveness of the Company’s internal control over financial reporting as of December 31, 2022, based on the framework established in Internal Control – Integrated Framework (2013) issued by the Committee of Sponsoring Organizations of the Treadway Commission (COSO). Based on this assessment, management concluded that the Company maintained effective internal control over financial reporting as of December 31, 2022. Ernst & Young LLP, the independent registered public accounting firm that audited the accompanying consolidated financial statements has issued its attestation report on the Company’s internal control over financial reporting,

March 17, 2023


/s/ Arun Banskota						/s/ Darren Myers
Chief Executive Officer						Chief Financial Officer

REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM

To the Shareholders and Directors of Algonquin Power & Utilities Corp.

Opinion on the Consolidated Financial Statements

We have audited the accompanying consolidated balance sheets of Algonquin Power & Utilities Corp. (the “Company”), as of December 31, 2022 and 2021, the related consolidated statements of operations, comprehensive income, equity and cash flows for the years then ended, and the related notes (collectively referred to as the “consolidated financial statements”). In our opinion, the consolidated financial statements present fairly, in all material respects, the financial position of the Company as of December 31, 2022 and 2021, and the results of its operations and its cash flows for the years then ended in conformity with U.S. generally accepted accounting principles.

We also have audited, in accordance with the standards of the Public Company Accounting Oversight Board (United States) (“PCAOB”), the Company’s internal control over financial reporting as of December 31, 2022, based on the criteria established in Internal Control – Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission (2013 framework), and our report dated March 17, 2023 expressed an unqualified opinion thereon.

Basis for Opinion

These financial statements are the responsibility of the Company‘s management. Our responsibility is to express an opinion on the Company‘s financial statements based on our audits. We are a public accounting firm registered with the PCAOB and are required to be independent with respect to the Company in accordance with the US federal securities laws and the applicable rules and regulations of the Securities and Exchange Commission and the PCAOB.

We conducted our audits in accordance with the standards of the PCAOB. Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement, whether due to error or fraud. Our audits included performing procedures to assess the risks of material misstatement of the financial statements, whether due to error or fraud, and performing procedures that respond to those risks. Such procedures include examining, on a test basis, evidence regarding the amounts and disclosures in the financial statements. Our audits also included evaluating the accounting principles used and significant estimates made by management, as well as evaluating the overall presentation of the financial statements. We believe that our audits provide a reasonable basis for our opinion.

Critical Audit Matters

The critical audit matters communicated below are matters arising from the current period audit of the financial statements that were communicated or required to be communicated to the audit committee and that: (1) relate to accounts or disclosures that are material to the financial statements and (2) involved our especially challenging, subjective, or complex judgments. The communication of critical audit matters does not alter in any way our opinion on the consolidated financial statements, taken as a whole, and we are not, by communicating the critical audit matters below, providing separate opinions on the critical audit matters or on the accounts or disclosures to which they relate.


						Regulatory assets and liabilities—Recovery of costs through rate regulation
Description of the Matter						As described in Note 7 to the consolidated financial statements, the Company has approximately $1.27 billion in regulatory assets and approximately $628.2 million in regulatory liabilities that are subject to regulation by the public utility commissions of the regions in which they operate. Rates are determined under cost of service regulation. The regulation of rates is premised on the full recovery of prudently incurred costs and a reasonable rate of return on assets or common shareholder’s equity. Regulatory decisions can have an impact on the timely recovery of costs and the approved returns. The recoverability of such costs through rate-regulation impacts multiple financial statement line items and disclosures, including property, plant, and equipment, regulatory assets and liabilities, derivative instruments, pension and other post-employment benefit obligation, regulated electricity, gas and water distribution revenues and the corresponding expenses, income tax expense, and depreciation and amortization expense. Although the Company expects to recover its costs from customers through rates, there is a risk that the respective regulator will not approve full recovery of the costs incurred. Auditing the recoverability of these costs through rates is complex and highly judgmental due to the significant judgments and probability assessments made by the Company to support its accounting and disclosure for regulatory matters when final regulatory decisions or orders have not yet been obtained or when regulatory formulas are complex. There is also subjectivity involved in assessing the potential impact of future regulatory decisions on the financial statements. The Company’s judgments include evaluating the probability of recovery of and recovery on costs incurred, or probability of refund to customers through future rates.
How We Addressed the Matter in Our Audit						We obtained an understanding, evaluated the design and tested the operating effectiveness of controls over the Company’s evaluation of the likelihood of recovery of regulatory assets and refund of regulatory liabilities, including management’s controls over the initial recognition and the monitoring and evaluation of regulatory developments that may affect the likelihood of recovering costs in future rates, a refund, or future changes in rates. We performed audit procedures that included, amongst others, evaluating the Company’s assessment of the probability of future recovery for regulatory assets and refund of regulatory liabilities, by comparison to the relevant regulatory orders, filings and correspondence, and other publicly available information including past precedents. For regulatory matters for which regulatory decisions or orders have not yet been obtained, we inspected the Company’s filings for any evidence that might contradict the Company’s assertions, and reviewed other regulatory orders, filings and correspondence for other entities within the same or similar jurisdictions to assess the likelihood of recovery in future rates based on the respective regulator’s treatment of similar costs under similar circumstances. We evaluated the Company’s analysis and compared that analysis with letters from legal counsel, when appropriate, regarding cost recoveries or future changes in rates. We also assessed the methodology and mathematical accuracy of the Company’s calculations of regulatory asset and liability balances based on provisions and formulas outlined in rate orders and other correspondence with regulators.


						Impairment of Long-lived Assets
Description of the Matter						As of December 31, 2022, the Company’s property, plant and equipment and finite-life intangible assets (collectively, long-lived assets) have an aggregate net book value of approximately $12 billion. As described in Note 1 to the consolidated financial statements, the Company reviews long-lived assets for impairment whenever events or changes in circumstances indicate that the carrying value of those assets may not be recoverable. Indicators of impairment may include a deteriorating business climate, including, but not limited to, declines in energy prices, or plans to dispose of a long-lived asset significantly before the end of its useful life. Management determines if long-lived assets are potentially impaired by comparing the undiscounted expected future cash flows to the carrying value when indicators of impairment exist. When the undiscounted cash flow analysis indicates a long-lived asset or asset group may not be recoverable, the amount of the impairment loss is determined by measuring the excess of the carrying amount of the long-lived asset or asset group over its fair value. In 2022, as disclosed in Note 5 to the consolidated financial statements, the Company recognized an asset impairment charge of $159.6 million, related to the Company’s Renewable Energy Group. Auditing the Company’s valuation of long-lived assets involved significant judgment to assess the recoverability and the fair value of these long-lived assets. The fair value analysis is primarily based on the income approach using significant assumptions that included the revenue forecasts driven by expected production, expected energy prices, and projected operating and capital expenditures and the discount rate, which were forward-looking and based upon expectations about future economic and market conditions.
How We Addressed the Matter in Our Audit						We obtained an understanding, evaluated the design and tested the operating effectiveness of the Company’s controls over the identification of impairment indicators and valuation of the long-lived asset, including management’s review controls of the valuation model, the significant assumptions used to develop the estimates, and the completeness and accuracy of the data used in the valuations. When testing the impairment analyses for the Renewable Energy Group, our audit procedures included, among others, obtaining an understanding of management’s strategic view of the facilities given market conditions, evaluating management’s assessment of the lowest level of identifiable cash flows, assessing the appropriateness of the methodology, testing the significant assumptions discussed above, testing the computational accuracy of the valuation model and testing the completeness and accuracy of the underlying data used by the Company in its analyses. We also performed audit procedures that included, among others, assessing the expected production through corroboration with third party engineering reports and historical trends. We assessed the projected operating expenditures by comparison to historical data and third party operating and maintenance agreements. With support of our valuation specialists, we assessed the projected capital expenditures by comparison to historical data and corroboration with independent market data and assessed the estimates of expected energy prices by comparison to historical data, executed power purchase agreements, and to relevant market curves. We also involved our valuation specialists in the evaluation of the discount rates, which included consideration of benchmark interest rates, geographic location and whether the asset is contracted or uncontracted. We also performed sensitivity analyses on significant assumptions to evaluate the changes in the fair value of the long-lived assets that would result from changes in the significant assumptions.


						Impairment of long-term investment in Texas Coastal Wind Facilities
Description of the Matter						As described in Note 8 to the consolidated financial statements, the balance of the Company’s equity method investment in Texas Coastal Wind Facilities, was $206.8 million as of December 31, 2022. Management periodically evaluates its equity method investments to determine whether an other-than-temporary decline in value has occurred and an impairment exists. Management determined that primarily as a result of continued challenges with congestion at the facilities, the carrying value of the interest in the Texas Coastal Wind Facilities required testing for an other-than-temporary impairment. Management assessed whether the fair value of its investment in Texas Coastal Wind Facilities had declined below its carrying value on an other-than-temporary basis in the fourth quarter of 2022. In the fourth quarter of 2022, as disclosed in Note 8 to the consolidated financial statements, the Company recorded an impairment charge of $75.9 million. Auditing the Company’s impairment assessment for Texas Coastal Wind Facilities was complex and required a high degree of auditor judgment, as the valuation included subjective estimates and assumptions in determining the estimated fair value of the investment. The fair value analysis is primarily based on the income approach using significant assumptions that included the expected revenue driven by production, expected energy prices, and projected operating and capital expenditures and the discount rate, which were forward-looking and based upon expectations about future economic and market conditions.
How We Addressed the Matter in Our Audit						We obtained an understanding, evaluated the design and tested the operating effectiveness of the Company’s controls over the equity method investment impairment review process, including management’s review controls of the valuation model, the significant assumptions used to develop the estimates, and the completeness and accuracy of the data used in the valuations. When testing the impairment analyses for Texas Coastal Wind Facilities, our audit procedures included, among others, assessing the appropriateness of the methodology, testing the significant assumptions discussed above, testing the computational accuracy of the valuation model and testing the completeness and accuracy of the underlying data used by the Company in its analyses. We also performed audit procedures that included, among others, assessing the expected production through corroboration with third party engineering reports and historical trends. We assessed the projected operating expenditures by comparison to historical data and third party operating and maintenance agreements. With support of our valuation specialists, we assessed the projected capital expenditures by comparison to historical data and corroboration with independent market data and assessed the expected energy prices by comparison to historical data, executed power purchase agreements, and relevant market curves. We also involved our valuation specialists in the evaluation of the discount rates, which included consideration of benchmark interest rates, geographic location and whether the asset is contracted or uncontracted. We also performed sensitivity analyses on significant assumptions to evaluate the changes in the fair value of the investment that would result from changes in the significant assumptions.


/s/ Ernst & Young LLP
Chartered Professional Accountants
Licensed Public Accountants

We have served as the Company's auditor since 2013.
Toronto, Canada
March 17, 2023

REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM

To the Shareholders and Directors of Algonquin Power & Utilities Corp.

Opinion on Internal Control over Financial Reporting

We have audited Algonquin Power & Utilities Corp.’s internal control over financial reporting as of December 31, 2022, based on criteria established in Internal Control—Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission (2013 framework) (the “COSO criteria”). In our opinion, Algonquin Power & Utilities Corp. (“the Company”) maintained, in all material respects, effective internal control over financial reporting as of December 31, 2022, based on the COSO criteria.

As indicated in the Management Report on Internal Controls over Financial Reporting section contained in the accompanying Management Discussion and Analysis, management’s assessment of and conclusion on the effectiveness of internal control over financial reporting did not include the internal controls of Liberty Utilities (New York Water) Corp. (“Liberty NY Water”), which is included in the 2022 consolidated financial statements of the Company and constituted 4% of the Company's total consolidated assets and 3% of the Company's total consolidated liabilities, respectively as of December 31, 2022, and 5% and 4% of the Company's consolidated revenue and operating income, respectively, for the year then ended. Our audit of internal control over financial reporting of the Company also did not include an evaluation of the internal control over financial reporting of Liberty NY Water.

We also have audited, in accordance with the standards of the Public Accounting Oversight Board (United States) (“PCAOB”), the consolidated balance sheets of the Company as of December 31, 2022 and 2021, the related consolidated statements of operations, comprehensive income, equity and cash flows for the years then ended, and the related notes, and our report dated March 17, 2023 expressed an unqualified opinion thereon.

Basis for Opinion

The Company’s management is responsible for maintaining effective internal control over financial reporting and for its assessment of the effectiveness of internal control over financial reporting included in the Management Report on Internal Controls over Financial Reporting section contained in the accompanying Management Discussion and Analysis. Our responsibility is to express an opinion on the Company’s internal control over financial reporting based on our audit. We are a public accounting firm registered with the PCAOB and are required to be independent with respect to the Company in accordance with the U.S. federal securities laws and the applicable rules and regulations of the Securities and Exchange Commission and the PCAOB.

We conducted our audit in accordance with the standards of the PCAOB. Those standards require that we plan and perform the audit to obtain reasonable assurance about whether effective internal control over financial reporting was maintained in all material respects.

Our audit included obtaining an understanding of internal control over financial reporting, assessing the risk that a material weakness exists, testing and evaluating the design and operating effectiveness of internal control based on the assessed risk, and performing such other procedures as we considered necessary in the circumstances. We believe that our audit provides a reasonable basis for our opinion.

Definition and Limitations of Internal Control Over Financial Reporting

A company’s internal control over financial reporting is a process designed to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles. A company’s internal control over financial reporting includes those policies and procedures that (1) pertain to the maintenance of records that, in reasonable detail, accurately and fairly reflect the transactions and dispositions of the assets of the company; (2) provide reasonable assurance that transactions are recorded as necessary to permit preparation of financial statements in accordance with generally accepted accounting principles, and that receipts and expenditures of the company are being made only in accordance with authorizations of management and directors of the company; and (3) provide reasonable assurance regarding prevention or timely detection of unauthorized acquisition, use, or disposition of the company’s assets that could have a material effect on the financial statements.

Because of its inherent limitations, internal control over financial reporting may not prevent or detect misstatements. Also, projections of any evaluation of effectiveness to future periods are subject to the risk that controls may become inadequate because of changes in conditions, or that the degree of compliance with the policies or procedures may deteriorate.


/s/ Ernst & Young LLP
Chartered Professional Accountants
Licensed Public Accountants


Toronto, Canada
March 17, 2023

Algonquin Power & Utilities Corp.

Consolidated Statements of Operations


	Year ended
(thousands of U.S. dollars, except per share amounts)	December 31
		2022		2021
Revenue
Regulated electricity distribution		$	1,277,409	$	1,183,399
Regulated natural gas distribution		686,744		525,897
Regulated water reclamation and distribution		364,383		234,875
Non-regulated energy sales		350,939		256,633
Other revenue		85,680		73,338
		2,765,155		2,274,142
Expenses
Operating expenses		851,489		702,128
Regulated electricity purchased		465,570		475,764
Regulated natural gas purchased		340,792		194,174
Regulated water purchased		18,308		12,664
Non-regulated energy purchased		41,826		31,313
Administrative expenses		80,232		66,726
Depreciation and amortization		455,520		402,963
Asset impairment charge (note 5)		159,568		—
Loss on foreign exchange		13,833		4,371
		2,427,138		1,890,103
Gain on sale of renewable assets (notes 3(a) and 16(c))		64,028		29,063
Operating income		402,045		413,102
Interest expense		(278,574)		(209,554)
Fair value change, income (loss) and impairment charge on long-term investments (note 8)		(465,206)		(26,457)
Other net losses (note 19)		(21,391)		(22,949)
Pension and other post-employment non-service costs (note 10)		(10,950)		(16,313)
Gain on derivative financial instruments (note 24(b)(iv))		4,408		4,403
		(771,713)		(270,870)
Income (loss) before income taxes		(369,668)		142,232
Income tax recovery (expense) (note 18)
Current		(7,843)		(7,237)
Deferred		69,356		50,662
		61,513		43,425


Net earnings (loss)		(308,155)		185,657
Net effect of non-controlling interests (note 17)
Non-controlling interests		111,323		89,637
Non-controlling interests held by related party		(15,157)		(10,435)
		$	96,166	$	79,202
Net earnings (loss) attributable to shareholders of Algonquin Power & Utilities Corp.		$	(211,989)	$	264,859
Preferred shares, Series A and preferred shares, Series D dividend (note 15)		8,720		9,003
Net earnings (loss) attributable to common shareholders of Algonquin Power & Utilities Corp.		$	(220,709)	$	255,856
Basic and diluted net earnings (loss) per share (note 20)		$	(0.33)	$	0.41

See accompanying notes to consolidated financial statements

Algonquin Power & Utilities Corp.

Consolidated Statements of Comprehensive Income


	Year ended
(thousands of U.S. dollars)	December 31
		2022		2021
Net earnings (loss)		$	(308,155)	$	185,657
Other comprehensive income (loss) (“OCI”):
Foreign currency translation adjustment, net of tax expense of $2,423 and recovery of $3,219, respectively (notes 24(b)(iii) and 24(b)(iv))		(23,502)		(30,270)
Change in fair value of cash flow hedges, net of tax expense of $20,644 and recovery of $22,077, respectively (note 24(b)(ii))		(94,295)		(54,331)

Change in pension and other post-employment benefits, net of tax expense of $8,330 and $9,176, respectively (note 10)		27,761		42,051
OCI, net of tax		(90,036)		(42,550)
Comprehensive income (loss)		(398,191)		143,107
Comprehensive loss attributable to the non-controlling interests		(97,816)		(78,953)
Comprehensive income (loss) attributable to shareholders of Algonquin Power & Utilities Corp.		$	(300,375)	$	222,060

See accompanying notes to consolidated financial statements

Algonquin Power & Utilities Corp.

Consolidated Balance Sheets


(thousands of U.S. dollars)
	December 31,		December 31,
	2022		2021
ASSETS
Current assets:
Cash and cash equivalents	$	57,623	$	125,157

Trade and other receivables, net (note 4)	528,057		403,426
Fuel and natural gas in storage	95,350		74,209
Supplies and consumables inventory	129,571		103,552
Regulatory assets (note 7)	190,393		158,212
Prepaid expenses	58,653		54,548
Derivative instruments (note 24)	12,270		3,486
Other assets (note 11)	22,564		16,153
	1,094,481		938,743
Property, plant and equipment, net (note 5)	11,944,885		11,042,446
Intangible assets, net (note 6)	96,683		105,116
Goodwill (note 6)	1,320,579		1,201,244
Regulatory assets (note 7)	1,081,108		1,009,413
Long-term investments (note 8)
Investments carried at fair value	1,344,207		1,848,456

Other long-term investments	462,325		495,826
Derivative instruments (note 24)	71,630		17,136
Deferred income taxes (note 18)	84,416		31,595

Other assets (note 11)	127,299		107,528
	$	17,627,613	$	16,797,503

See accompanying notes to consolidated financial statements

Algonquin Power & Utilities Corp.

Consolidated Balance Sheets (continued)


(thousands of U.S. dollars)
	December 31,		December 31,
	2022		2021
LIABILITIES AND EQUITY
Current liabilities:
Accounts payable	$	186,080	$	185,291
Accrued liabilities	555,792		428,733
Dividends payable (note 15)	125,655		114,544
Regulatory liabilities (note 7)	69,865		65,809
Long-term debt (note 9)	423,274		356,397
Other long-term liabilities (note 12)	134,212		167,908
Derivative instruments (note 24)	32,491		38,569
Other liabilities	7,091		7,461
	1,534,460		1,364,712
Long-term debt (note 9)	7,088,743		5,854,978
Regulatory liabilities (note 7)	558,317		510,380
Deferred income taxes (note 18)	565,639		530,187
Derivative instruments (note 24)	137,830		81,676
Pension and other post-employment benefits obligation (note 10)	125,579		238,054
Other long-term liabilities (note 12)	461,230		515,911

	8,937,338		7,731,186
Redeemable non-controlling interests (note 17)
Redeemable non-controlling interest, held by related party	307,856		306,537
Redeemable non-controlling interests	11,520		12,989
	319,376		319,526
Equity:
Preferred shares	184,299		184,299
Common shares (note 13(a))	6,183,943		6,032,792

Additional paid-in capital	9,413		2,007
Deficit	(997,945)		(288,424)
Accumulated other comprehensive loss (“AOCI”) (note 14)	(160,063)		(71,677)
Total equity attributable to shareholders of Algonquin Power & Utilities Corp.	5,219,647		5,858,997
Non-controlling interests (note 17)
Non-controlling interests - tax equity partnership units	1,225,608		1,377,117
Other non-controlling interests	333,362		64,807
Non-controlling interest, held by related party	57,822		81,158
	1,616,792		1,523,082
Total equity	6,836,439		7,382,079
Commitments and contingencies (note 22)
Subsequent events (notes 3(b), 7, 9(a), 9(d) and 13(a))
	$	17,627,613	$	16,797,503

See accompanying notes to consolidated financial statements

Algonquin Power & Utilities Corp.

Consolidated Statement of Equity


(thousands of U.S. dollars) For the year ended December 31, 2022

	Algonquin Power & Utilities Corp. Shareholders
	Common shares		Preferred shares		Additional paid-in capital		Retained earnings (deficit)		AOCI		Non- controlling interests		Total
Balance, December 31, 2021	$	6,032,792	$	184,299	$	2,007	$	(288,424)	$	(71,677)	$	1,523,082	$	7,382,079

Net loss	—		—		—		(211,989)		—		(96,166)		(308,155)
Effect of redeemable non-controlling interests not included in equity (note 17)	—		—		—		—		—		(8,859)		(8,859)
OCI	—		—		—		—		(88,386)		(1,650)		(90,036)
Dividends declared and distributions to non-controlling interests	—		—		—		(396,965)		—		(61,063)		(458,028)
Dividends and issuance of shares under dividend reinvestment plan	97,801		—		—		(97,801)		—		—		—
Contributions received from non-controlling interests, net of cost	—		—		—		—		—		273,697		273,697

Common shares issued upon conversion of convertible debentures	6		—		—		—		—		—		6
Common shares issued upon public offering, net of tax effected cost	38,227		—		—		—		—		—		38,227

Common shares issued under employee share purchase plan	5,319		—		—		—		—		—		5,319
Share-based compensation	—		—		14,849		—		—		—		14,849
Common shares issued pursuant to share-based awards	9,798		—		(14,743)		(2,766)		—		—		(7,711)
Repurchase of non-controlling interest (note 17)	—		—		7,300		—		—		(12,249)		(4,949)
Balance, December 31, 2022	$	6,183,943	$	184,299	$	9,413	$	(997,945)	$	(160,063)	$	1,616,792	$	6,836,439

See accompanying notes to consolidated financial statements

Algonquin Power & Utilities Corp.

Consolidated Statement of Equity (continued)


(thousands of U.S. dollars) For the year ended December 31, 2021

	Algonquin Power & Utilities Corp. Shareholders
	Common shares		Preferred shares		Additional paid-in capital		Deficit		AOCI		Non- controlling interests		Total
Balance, December 31, 2020	$	4,935,304	$	184,299	$	60,729	$	45,753	$	(22,507)	$	458,612	$	5,662,190
Net earnings (loss)	—		—		—		264,859		—		(79,202)		185,657
Effect of redeemable non-controlling interests not included in equity (note 17)	—		—		—		—		—		(4,866)		(4,866)
OCI	—		—		—		—		(42,799)		249		(42,550)
Dividends declared and distributions to non-controlling interests	—		—		—		(339,531)		—		(30,609)		(370,140)
Dividends and issuance of shares under dividend reinvestment plan	92,495		—		—		(92,495)		—		—		—
Contributions received from non-controlling interests, net of cost	—		—		6,919		—		(6,371)		1,149,757		1,150,305
Common shares issued upon conversion of convertible debentures	16		—		—		—		—		—		16
Common shares issued upon public offering, net of tax effected cost	988,886		—		—		—		—		—		988,886
Contract adjustment payments	—		—		(62,240)		(160,138)		—		—		(222,378)
Common shares issued under employee share purchase plan	5,108		—		—		—		—		—		5,108
Share-based compensation	—		—		10,036		—		—		—		10,036
Common shares issued pursuant to share-based awards	10,983		—		(13,437)		(6,872)		—		—		(9,326)
Non-controlling interest assumed on asset acquisition (note 3(d))	—		—		—		—		—		29,141		29,141
Balance, December 31, 2021	$	6,032,792	$	184,299	$	2,007	$	(288,424)	$	(71,677)	$	1,523,082	$	7,382,079

See accompanying notes to consolidated financial statements

Algonquin Power & Utilities Corp.

Consolidated Statements of Cash Flows


(thousands of U.S. dollars)	Year ended December 31
		2022		2021
Cash provided by (used in):
Operating activities
Net earnings (loss)		$	(308,155)	$	185,657
Adjustments and items not affecting cash:
Depreciation and amortization		455,520		402,963
Deferred taxes		(69,356)		(50,662)
Initial value and unrealized loss (gain) on derivative financial instruments		2,462		(5,609)
Share-based compensation		10,920		8,395
Cost of equity funds used for construction purposes		(1,896)		(637)
Change in value of investments carried at fair value		499,125		122,419
Pension and post-employment expense lower than contributions		(15,329)		(14,146)
Distributions received from equity investments, net of income		23,829		29,818
Impairment of assets		235,478		—
Other		8,116		1,290
Net change in non-cash operating items (note 23)		(221,618)		(522,022)
		619,096		157,466
Financing activities
Increase in long-term debt		16,825,796		12,834,047
Repayments of long-term debt		(15,461,078)		(12,895,091)

Issuance of common shares, net of costs		43,546		985,619
Cash dividends on common shares		(378,597)		(307,115)
Dividends on preferred shares		(8,720)		(9,003)

Contributions from non-controlling interests and redeemable non-controlling interests		272,515		1,125,548
Production-based cash contributions from non-controlling interest		6,182		4,832
Distributions to non-controlling interests, related party (note 17)		(34,816)		(28,007)
Distributions to non-controlling interests		(43,919)		(12,830)

Payments upon settlement of derivatives		(28,913)		(33,782)
Shares surrendered to fund withholding taxes on exercised share options		(4,667)		(3,372)
Acquisition of non-controlling interest		(1,580)		—
Increase in other long-term liabilities		19,324		62,000
Decrease in other long-term liabilities		(94,837)		(49,130)
		1,110,236		1,673,716
Investing activities

Additions to property, plant and equipment and intangible assets		(1,089,024)		(1,345,045)
Increase in long-term investments		(221,281)		(622,320)
Acquisitions of operating entities (note 3(c))		(632,797)		—

Increase in other assets		(26,527)		(43,306)
Receipt of principal on development loans receivable		178,300		206,319

Decrease in long-term investments		2,920		220
Other proceeds		—		6,023
		(1,788,409)		(1,798,109)
Effect of exchange rate differences on cash and restricted cash		(1,127)		(1,702)
Increase (decrease) in cash, cash equivalents and restricted cash		(60,204)		31,371
Cash, cash equivalents and restricted cash, beginning of year		161,389		130,018
Cash, cash equivalents and restricted cash, end of year		$	101,185	$	161,389



Algonquin Power & Utilities Corp. Consolidated Statements of Cash Flows (continued)

(thousands of U.S. dollars)	Year ended December 31
		2022		2021
Supplemental disclosure of cash flow information:
Cash paid during the year for interest expense		$	272,734	$	219,025
Cash paid during the year for income taxes		$	10,962	$	5,019
Cash received during the year for distributions from equity investments		$	112,951	$	112,309
Non-cash financing and investing activities:
Property, plant and equipment acquisitions in accruals		$	120,819	$	103,427
Issuance of common shares under dividend reinvestment plan and share-based compensation plans		$	112,918	$	108,586

Property, plant and equipment, intangible assets and accrued liabilities in exchange of note receivable		$	90,700	$	90,821

See accompanying notes to consolidated financial statements


Algonquin Power & Utilities Corp.
Notes to the Consolidated Financial Statements
December 31, 2022 and 2021
(in thousands of U.S. dollars, except as noted and per share amounts)

Algonquin Power & Utilities Corp. (“AQN” or the “Company”) is an incorporated entity under the Canada Business Corporations Act. AQN's operations are organized across two primary business units consisting of the Regulated Services Group and the Renewable Energy Group. The Regulated Services Group owns and operates a portfolio of regulated electric, water distribution and wastewater collection, and natural gas utility systems and transmission operations in the United States, Canada, Bermuda and Chile; the Renewable Energy Group owns and operates, or has investments in, a diversified portfolio of non-regulated renewable and thermal energy generation assets.

1.Significant accounting policies

(a)Basis of preparation

The accompanying consolidated financial statements and notes have been prepared in accordance with generally accepted accounting principles in the United States (“U.S. GAAP”) and follow disclosure required under Regulation S-X provided by the U.S. Securities and Exchange Commission.

(b)Basis of consolidation

The accompanying consolidated financial statements of AQN include the accounts of AQN, its wholly owned subsidiaries and variable interest entities (“VIEs”) where the Company is the primary beneficiary (note 1(m)). Intercompany transactions and balances have been eliminated. Interests in subsidiaries owned by third parties are included in non-controlling interests (note 1(s)).

(c)Business combinations, intangible assets and goodwill

The Company accounts for acquisitions of entities or assets that meet the definition of a business as business combinations. Business combinations are accounted for using the acquisition method. Assets acquired and liabilities assumed are measured at their fair value at the acquisition date, except for deferred income taxes, which are accounted for as described in note 1(v). Acquisition costs are expensed in the period incurred. When the set of activities does not represent a business, the transaction is accounted for as an asset acquisition and includes acquisition costs.

Intangible assets acquired are recognized separately at fair value if they arise from contractual or other legal rights or are separable. Power sales contracts are amortized on a straight-line basis over the remaining term of the contract ranging from 6 to 25 years from the date of acquisition. Interconnection agreements are amortized on a straight-line basis over their estimated life of 40 years. The majority of the Company's customer relationships are amortized on a straight-line basis over their estimated lives of 25 to 40 years. Certain customer relationships and water rights in Chile as well as brand names are considered indefinite-lived intangibles and are not amortized, but assessed annually for indicators of impairment. Miscellaneous intangibles include renewable energy credits that are purchased by the Company's electric utilities to satisfy renewable portfolio standard obligations. These intangibles are not amortized but are derecognized when remitted to the respective state authority to satisfy the compliance obligation.

Goodwill represents the excess of the purchase price of an acquired business over the fair value of the net assets acquired. Goodwill is generally not included in the rate base on which regulated utilities are allowed to earn a return and is not amortized.

As at September 30 of each year, the Company assesses qualitative and quantitative factors to determine whether it is more likely than not that the fair value of a reporting unit to which goodwill is attributed is less than its carrying amount. If it is more likely than not that a reporting unit’s fair value is less than its carrying amount or if a quantitative assessment is elected, the Company calculates the fair value of the reporting unit. If the carrying amount of the reporting unit as a whole exceeds the reporting unit’s fair value, an impairment charge is recorded in an amount of that excess, limited to the total amount of goodwill allocated to that reporting unit. Goodwill is tested for impairment between annual tests if an event occurs or circumstances change that would more likely than not reduce the fair value of a reporting unit below its carrying amount.


Algonquin Power & Utilities Corp.
Notes to the Consolidated Financial Statements
December 31, 2022 and 2021
(in thousands of U.S. dollars, except as noted and per share amounts)

1.Significant accounting policies (continued)

(d)Accounting for rate regulated operations

The operating companies within the Regulated Services Group are subject to rate regulation generally overseen by the regulatory authorities of the jurisdictions in which they operate (the “Regulator”). The Regulator provides the final determination of the rates charged to customers. AQN’s regulated operating companies are accounted for under the principles of U.S. Financial Accounting Standards Board (“FASB”) ASC Topic 980, Regulated Operations (“ASC 980”) except for AQN's Chilean operating company, Empresa de Servicios de Los Lagos S.A. (“ESSAL”), which was acquired in October 2020. The rates that are approved under the Chilean regulatory framework are designed to recover the costs of service of a model water utility. Because the rates are not designed to recover ESSAL's specific costs of service, the utility does not meet the criteria to follow the accounting guidance under ASC 980.

Under ASC 980, regulatory assets and liabilities are recorded to the extent that they represent probable future revenue or expenses associated with certain charges or credits that will be recovered from or refunded to customers through the rate making process. Included in note 7, “Regulatory matters”, are details of regulatory assets and liabilities, and their current regulatory treatment.

In the event the Company determines that its net regulatory assets are not probable of recovery, it would no longer apply the principles of the current accounting guidance for rate regulated enterprises and would be required to record an after-tax, non-cash charge or credit against earnings for any remaining regulatory assets or liabilities. The impact could be material to the Company’s reported financial condition and results of operations.

The U.S. electric, gas and water utilities’ accounts are maintained in accordance with the Uniform System of Accounts prescribed by the Federal Energy Regulatory Commission (“FERC”), the applicable Regulator(s) and National Association of Regulatory Utility Commissioners in the United States. The New Brunswick Gas accounts are maintained in accordance with the New Brunswick Gas Distribution Act Uniform Accounting Regulation.

(e)Cash and cash equivalents

Cash and cash equivalents include all highly liquid instruments with an original maturity of three months or less.

(f)Restricted cash

Restricted cash represents reserves and amounts set aside pursuant to requirements of various debt agreements, deposits to be returned back to customers, and certain requirements related to generation and transmission operations. Cash reserves segregated from AQN’s cash balances are maintained in accounts administered by a separate agent and disclosed separately as restricted cash in these consolidated financial statements. AQN cannot access restricted cash without the prior authorization of parties not related to AQN.

(g)Accounts receivable

Trade accounts receivable are recorded at the invoiced amount and do not bear interest. The Company maintains an allowance for doubtful accounts for estimated losses inherent in its accounts receivable portfolio. In establishing the required allowance, management considers historical losses adjusted to take into account current market conditions and customers’ financial condition, the amount of receivables in dispute, future economic conditions and outlook, and the receivables aging and current payment patterns. Account balances are charged against the allowance after all means of collection have been exhausted and the potential for recovery is considered remote. The Company does not have any off-balance sheet credit exposure related to its customers.


Algonquin Power & Utilities Corp.
Notes to the Consolidated Financial Statements
December 31, 2022 and 2021
(in thousands of U.S. dollars, except as noted and per share amounts)

1.Significant accounting policies (continued)

(h)Fuel and natural gas in storage

Fuel and natural gas in storage is reflected at weighted average cost or first-in-first-out as required by regulators and represents fuel, natural gas and liquefied natural gas that will be utilized in the ordinary course of business of the gas utilities and some generating facilities. Existing rate orders and other contracts allow the Company to pass through the cost of gas purchased directly to the customers along with any applicable authorized delivery surcharge adjustments (note 7(a)). Accordingly, the net realizable value of fuel and gas in storage does not fall below the cost to the Company.

(i)Supplies and consumables inventory

Supplies and consumables inventory (other than capital spares and rotatable spares, which are included in property, plant and equipment) are charged to inventory when purchased and then capitalized to plant or expensed, as appropriate, when installed, used or upon becoming obsolete. These items are stated at the lower of cost and net realizable value. Through rate orders and the regulatory environment, capitalized construction jobs are recovered through rate base and repair and maintenance expenses are recovered through a cost of service calculation. Accordingly, the cost usually reflects the net realizable value.

(j)Property, plant and equipment

Property, plant and equipment are recorded at cost. Capitalization of development projects begins when management with the relevant authority has authorized and committed to the funding of a project and it is probable that costs will be realized through the use of the asset or ultimate construction and operation of a facility. Project development costs for rate regulated entities, including expenditures for preliminary surveys, plans, investigations, environmental studies, regulatory applications and other costs incurred for the purpose of determining the feasibility of capital expansion projects, are capitalized either as regulatory assets or property, plant and equipment when it is determined that recovery of such costs through regulated revenue of the completed project is probable.

The costs of acquiring or constructing property, plant and equipment include the following: materials, labour, contractor and professional services, construction overhead directly attributable to the capital project (where applicable), interest for non-regulated property and allowance for funds used during construction (“AFUDC”) for regulated property. Where possible, individual components are recorded and depreciated separately in the books and records of the Company. Plant and equipment under finance leases are initially recorded at cost determined as the present value of lease payments to be made over the lease term.

AFUDC represents the cost of borrowed funds and a return on other funds. Under ASC 980, an allowance for funds used during construction projects that are included in rate base is capitalized. This allowance is designed to enable a utility to capitalize financing costs during periods of construction of property subject to rate regulation. For operations that do not apply regulatory accounting, interest related only to debt is capitalized as a cost of construction in accordance with ASC 835, Interest. The interest capitalized that relates to debt reduces interest expense on the consolidated statements of operations. The AFUDC capitalized that relates to equity funds is recorded as interest and other income under income from long-term investments on the consolidated statements of operations.

Improvements that increase or prolong the service life or capacity of an asset are capitalized. Costs incurred for major expenditures or overhauls that occur at regular intervals over the life of an asset are capitalized and depreciated over the related interval. Maintenance and repair costs are expensed as incurred. Grants related to capital expenditures are recorded as a reduction to the cost of assets and are amortized at the rate of the related asset as a reduction to depreciation expense. Grants related to operating expenses such as maintenance and repairs costs are recorded as a reduction of the related expense. Contributions in aid of construction represent amounts contributed by customers, governments and developers to assist with the funding of some or all of the cost of utility capital assets. They also include amounts initially recorded as advances in aid of construction (note 12(c)) once the advance repayment period has expired. These contributions are recorded as a reduction in the cost of utility assets and are amortized at the rate of the related asset as a reduction to depreciation expense.


Algonquin Power & Utilities Corp.
Notes to the Consolidated Financial Statements
December 31, 2022 and 2021
(in thousands of U.S. dollars, except as noted and per share amounts)

1.Significant accounting policies (continued)

(j)Property, plant and equipment (continued)

The Company’s depreciation is based on the estimated useful lives of the depreciable assets in each category and is determined using the straight-line method with the exception of certain wind assets, as described below. The ranges of estimated useful lives and the weighted average useful lives are summarized below:


	Range of useful lives		Weighted average useful lives
	2022	2021	2022	2021
Generation	3-60	3-60	33	33
Distribution	1-100	1-100	39	40
Equipment	5-54	5-50	11	11

The Company uses the unit-of-production method for certain components of its wind generating facilities where the useful life of the component is directly related to the amount of production. The benefits of components subject to wear and tear from the power generation process are best reflected through the unit-of-production method. The Company generally uses wind studies prepared by third parties to estimate the total expected production of each component.

In accordance with regulator-approved accounting policies, when depreciable property, plant and equipment of the Regulated Services Group are replaced or retired, the original cost plus any removal costs incurred (net of salvage) are charged to accumulated depreciation with no gain or loss reflected in results of operations. Gains and losses will be charged to results of operations in the future through adjustments to depreciation expense. In the absence of regulator-approved accounting policies, gains and losses on the disposition of property, plant and equipment are charged to earnings as incurred.

(k)Commonly owned facilities

The Regulated Services Group owns undivided interests in three electric generating facilities with ownership interest ranging from 7.52% to 60%, with a corresponding share of capacity and generation from the facility used to serve certain of its utility customers. The Company's investment in the undivided interest is recorded as plant in service and recovered through rate base. Commonly owned facilities represent cost of $559,630 (2021 - $557,954) and accumulated depreciation of $75,820 (2021 - $59,857). The Company's share of operating costs is recognized in operating, maintenance and fuel expenditures excluding depreciation expense. Total expenditures incurred on these facilities for the year ended December 31, 2022 were $110,268 (2021 - $143,255).

(l)Impairment of long-lived assets

AQN reviews property, plant and equipment and finite-life intangible assets for impairment whenever events or changes in circumstances indicate the carrying amount may not be recoverable.

As at September 30 of each year, the Company assesses qualitative factors to determine whether it is more likely than not that the indefinite-lived intangible is impaired. If it is more likely than not that the indefinite-lived intangible asset is impaired, the Company calculates the fair value of the intangible asset. If the carrying value of the intangible asset exceeds its fair value, the Company recognizes an impairment loss in an amount equal to that excess. Indefinite-life intangibles are tested for impairment between annual tests if an event occurs or circumstances change that would more likely than not reduces the fair value below its carrying amount.

Recoverability of assets expected to be held and used is measured by comparing the carrying amount of an asset to undiscounted expected future cash flows. If the carrying amount exceeds the recoverable amount, the asset is written down to its fair value. During the fourth quarter of 2022, the Company recorded an impairment charge of $159,568 to reduce the carrying value of the Senate Wind Facility and other smaller assets from $259,942 to $100,374 (note 5).


Algonquin Power & Utilities Corp.
Notes to the Consolidated Financial Statements
December 31, 2022 and 2021
(in thousands of U.S. dollars, except as noted and per share amounts)

1.Significant accounting policies (continued)

(m)Variable interest entities

The Company performs analyses to assess whether its operations and investments represent VIEs. To identify potential VIEs, management reviews contracts under leases, long-term purchase power agreements and jointly owned facilities. VIEs for which the Company is deemed the primary beneficiary are consolidated. In circumstances where AQN is not deemed the primary beneficiary, the VIE is not consolidated (note 8).

The Company has equity and notes receivable interests in two power generating facilities. AQN has determined that these entities are considered VIEs mainly based on total equity at risk not being sufficient to permit the legal entity to finance its activities without additional subordinated financial support. The key decisions that affect the generating facilities’ economic performance relate to siting, permitting, technology, construction, operations and maintenance and financing. As AQN has both the power to direct the activities of the entities that most significantly impact its economic performance and the right to receive benefits or the obligation to absorb losses of the entities that could potentially be significant to the entities, the Company is considered the primary beneficiary.

Total net book value of assets and long-term debt of these facilities amounts to $57,241 (2021 - $59,877) and $15,024 (2021 - 18,344), respectively. The financial performance of these entities reflected on the consolidated statements of operations includes non-regulated energy sales of $19,752 (2021 - 16,772), operating expenses and amortization of $5,834 (2021 - $5,410) and interest expense of $1,723 (2021 - $2,055).

(n)Long-term investments and notes receivable

Investments in which AQN has significant influence but not control are either accounted for using the equity method or at fair value. Equity-method investments are initially measured at cost including transaction costs and interest when applicable. AQN records its share in the income or loss of its equity-method investees in income from long-term investments in the consolidated statements of operations. AQN records in the consolidated statements of operations the fluctuations in the fair value of its investees held at fair value and dividend income when it is declared by the investee.

Notes receivable are financial assets with fixed or determined payments that are not quoted in an active market. Notes receivable are initially recorded at cost, which is generally face value. Subsequent to acquisition, the notes receivable are recorded at amortized cost using the effective interest method. The Company holds these notes receivable as long-term investments and does not intend to sell these instruments prior to maturity. Interest from long-term investments is recorded as earned and when collectability of both the interest and principal are reasonably assured.

If a loss in value of a long-term investment is considered other than temporary, an allowance for impairment on the investment is recorded for the amount of that loss. An allowance on notes receivable is recorded in order to present the net amount expected to be collected on the receivable. This allowance reflects the risk of loss over the remaining contractual life of the asset, taking into consideration historical experience, current conditions, and reasonable and supportable forecasts of future economic conditions. The impairment is measured based on the present value of expected future cash flows discounted at the note’s effective interest rate. During the fourth quarter of 2022, the Renewable Energy Group recorded an impairment charge of $75,910 to reduce the carrying value of its equity investment in the Texas Coastal Wind Facilities (as defined herein) from $282,726 to 206,816 (note 8(c)).


Algonquin Power & Utilities Corp.
Notes to the Consolidated Financial Statements
December 31, 2022 and 2021
(in thousands of U.S. dollars, except as noted and per share amounts)

1.Significant accounting policies (continued)

(o)Pension and other post-employment plans

The Company has established defined contribution pension plans, defined benefit pension plans, other post-employment benefit (“OPEB”) plans, and supplemental retirement program (“SERP”) plans for its various employee groups. Employer contributions to the defined contribution pension plans are expensed as employees render service. The Company recognizes the funded status of its defined benefit pension plans, OPEB and SERP plans on the consolidated balance sheets. The Company’s expense and liabilities are determined by actuarial valuations, using assumptions that are evaluated annually as of December 31, including discount rates, mortality, assumed rates of return, compensation increases, turnover rates and healthcare cost trend rates. The impact of modifications to those assumptions and modifications to prior services are recorded as actuarial gains and losses in accumulated other comprehensive income (“AOCI”) and amortized to net periodic cost over future periods using the corridor method. When settlements of the Company's pension plans occur, the Company recognizes associated gains or losses immediately in earnings if the cost of all settlements during the year is greater than the sum of the service cost and interest cost components of the pension plan for the year. The amount recognized is a pro rata portion of the gains and losses in AOCI equal to the percentage reduction in the projected benefit obligation as a result of the settlement.

The costs of the Company’s pension for employees are expensed over the periods during which employees render service and the service costs are recognized as part of administrative expenses in the consolidated statements of operations. The components of net periodic benefit cost other than the service cost component are included in other net losses in the consolidated statements of operations.

(p)Asset retirement obligations

The Company recognizes a liability for asset retirement obligations based on the fair value of the liability when incurred, which is generally upon acquisition, during construction or through the normal operation of the asset. Concurrently, the Company also capitalizes an asset retirement cost, equal to the estimated fair value of the asset retirement obligation, by increasing the carrying value of the related long-lived asset. The asset retirement costs are depreciated over the asset’s estimated useful life and are included in depreciation and amortization expense on the consolidated statements of operations. Increases in the asset retirement obligation resulting from the passage of time are recorded as accretion of asset retirement obligation in the consolidated statements of operations. Actual expenditures incurred are charged against the obligation.

(q)Leases

The Company accounts for leases in accordance with ASC Topic 842, Leases. The Company leases land, buildings, vehicles, rail cars, and office equipment for use in its day-to-day operations. The Company has options to extend the lease term of many of its lease agreements, with renewal periods ranging from one to five years. As at the consolidated balance sheet date, the Company is not reasonably certain that these renewal options will be exercised.

The Renewable Energy Group enters into land easement agreements for the operation of its generation facilities. In assessing whether these contracts contain leases, the Company considers whether it has exclusive use of the land. In the majority of situations, the landowner or grantor of the easement still has full access to the land and can use the land in any capacity, as long as it does not interfere with the Company’s operations. Therefore, these land easement agreements do not contain leases. For land easement agreements that provide exclusive access to and use of the land, these agreements meet the definition of a lease and are within the scope of ASC 842.

The right-of-use assets are included in property, plant and equipment while lease liabilities are included in other liabilities on the consolidated balance sheets. The discount rates used in the measurement of the Company's right-of-use assets and liabilities are the discount rates at the date of lease inception. The Company's lease balances as at December 31, 2022 and its expected lease payments for the next five years and thereafter are not significant.


Algonquin Power & Utilities Corp.
Notes to the Consolidated Financial Statements
December 31, 2022 and 2021
(in thousands of U.S. dollars, except as noted and per share amounts)

1.Significant accounting policies (continued)

(r)Share-based compensation

The Company has several share-based compensation plans: a share option plan; an employee share purchase plan (“ESPP”); a deferred share unit (“DSU”) plan; and a restricted share unit (“RSU”) and performance share unit (“PSU”) plan. Equity-classified awards are measured at the grant date fair value of the award. The Company estimates grant date fair value of options using the Black-Scholes option pricing model. The fair value is recognized over the vesting period of the award granted, adjusted for estimated forfeitures. The compensation cost is recorded as administrative expenses in the consolidated statements of operations and additional paid-in capital in equity. Additional paid-in capital is reduced as the awards are exercised, and the amount initially recorded in additional paid-in capital is credited to common shares.

(s)Non-controlling interests

Non-controlling interests represent the portion of equity ownership in subsidiaries that is not attributable to the equity holders of AQN. Non-controlling interests are initially recorded at fair value and subsequently adjusted for the proportionate share of earnings and other comprehensive income (“OCI”) attributable to the non-controlling interests and any dividends or distributions paid to the non-controlling interests.

If a transaction results in the acquisition of all, or part, of a non-controlling interest in a consolidated subsidiary, the acquisition of the non-controlling interest is accounted for as an equity transaction. No gain or loss is recognized in net earnings or comprehensive income as a result of changes in the non-controlling interest, unless a change results in the loss of control by the Company.

Certain of the Company’s U.S. based wind and solar businesses are organized as limited liability corporations (“LLCs”) and partnerships and have non-controlling membership equity investors (“tax equity partnership units”, or “Tax Equity Investors”), which are entitled to allocations of earnings, tax attributes and cash flows in accordance with contractual agreements. These LLCs and partnership agreements have liquidation rights and priorities that are different from the underlying percentage ownership interests. In those situations, simply applying the percentage ownership interest to U.S. GAAP net income in order to determine earnings or losses would not accurately represent the income allocation and cash flow distributions that will ultimately be received by the investors. As such, the share of earnings attributable to the non-controlling interest holders in these entities is calculated using the Hypothetical Liquidation at Book Value (“HLBV”) method of accounting (note 17).

The HLBV method uses a balance sheet approach. A calculation is prepared at each balance sheet date to

determine the amount that Tax Equity Investors would receive if an equity investment entity were to liquidate all of its assets and distribute that cash to the investors based on the contractually defined liquidation priorities. The difference between the calculated liquidation distribution amounts at the beginning and the end of the reporting period is the Tax Equity Investors' share of the earnings or losses from the investment for that period.

Equity instruments subject to redemption upon the occurrence of uncertain events not solely within AQN’s control are classified as temporary equity and presented as redeemable non-controlling interests on the consolidated balance sheets. The Company records temporary equity at issuance based on cash received less any transaction costs. As needed, the Company reevaluates the classification of its redeemable instruments, as well as the probability of redemption. If the redemption amount is probable or currently redeemable, the Company records the instruments at their redemption value. Increases or decreases in the carrying amount of a redeemable instrument are recorded within deficit. When the redemption feature lapses or other events cause the classification of an equity instrument as temporary equity to be no longer required, the existing carrying amount of the equity instrument is reclassified to permanent equity at the date of the event that caused the reclassification.

(t)Recognition of revenue

Revenue is recognized when control of the promised goods or services is transferred to the Company’s customers in an amount that reflects the consideration the Company expects to be entitled to in exchange for those goods or services.

Refer to note 21, “Segmented information” for details of revenue disaggregation by business units.


Algonquin Power & Utilities Corp.
Notes to the Consolidated Financial Statements
December 31, 2022 and 2021
(in thousands of U.S. dollars, except as noted and per share amounts)

1.Significant accounting policies (continued)

(t)Recognition of revenue (continued)

Regulated Services Group revenue

Regulated Services Group revenue derives primarily from the distribution of electricity, water and natural gas.

Revenue related to utility electricity and natural gas sales and distribution is recognized over time as the energy is delivered. At the end of each month, the electricity and natural gas delivered to the customers from the date of their last meter read to the end of the month is estimated and the corresponding unbilled revenue is recorded. These estimates of unbilled revenue and sales are based on the ratio of billable days versus unbilled days, amount of electricity or natural gas procured during that month, historical customer class usage patterns, weather, line loss, unaccounted-for natural gas and current tariffs. Unbilled receivables are typically billed within the next month. Some customers elect to pay their bill on an equal monthly plan.

As a result, in some months cash is received in advance of the delivery of electricity. Deferred revenue is recorded for that amount. The amount of revenue recognized in the period from the balance of deferred revenue is not significant.

Water reclamation and distribution revenue is recognized over time when water is processed or delivered to customers. At the end of each month, the water delivered and wastewater collected from the customers from the date of their last meter read to the end of the month are estimated and the corresponding unbilled revenue is recorded. These estimates of unbilled revenue are based on the ratio of billable days versus unbilled days, amount of water procured and collected during that month, historical customer class usage patterns and current tariffs. Unbilled receivables are typically billed within the next month.

On occasion, a utility is permitted to implement new rates that have not been formally approved by the regulatory commission, which are subject to refund. The Company recognizes revenue based on the interim rate and, if needed, establishes a reserve for amounts that could be refunded based on experience for the jurisdiction in which the rates were implemented.

Revenue for certain of the Company’s regulated utilities is subject to alternative revenue programs approved by their respective regulators. Under these programs, the Company charges approved annual delivery revenue on a systematic basis over the fiscal year. As a result, the difference between delivery revenue calculated based on metered consumption and approved delivery revenue is disclosed as alternative revenue in note 21, “Segmented information” and is recorded as a regulatory asset or liability to reflect future recovery or refund, respectively, from customers (note 7). The amount subsequently billed to customers is recorded as a recovery of the regulatory asset.

Renewable Energy Group revenue

Renewable Energy Group's revenue derives primarily from the sale of electricity, capacity, and renewable energy credits.

Revenue related to the sale of electricity is recognized over time as the electricity is delivered. The electricity represents a single performance obligation that represents a promise to transfer to the customer a series of distinct goods that are substantially the same and that have the same pattern of transfer to the customer.

Revenue related to the sale of capacity is recognized over time as the capacity is provided. The nature of the promise to provide capacity is that of a stand-ready obligation. The capacity is generally expressed in monthly volumes and prices. The capacity represents a single performance obligation that represents a promise to transfer to the customer a series of distinct services that are substantially the same and that have the same pattern of transfer to the customer.


Algonquin Power & Utilities Corp.
Notes to the Consolidated Financial Statements
December 31, 2022 and 2021
(in thousands of U.S. dollars, except as noted and per share amounts)

1.Significant accounting policies (continued)

(t)Recognition of revenue (continued)

Renewable Energy Group revenue (continued)

Qualifying renewable energy projects receive renewable energy credits (“RECs”) and solar renewable energy credits (“SRECs”) for the generation and delivery of renewable energy to the power grid. The energy credit certificates represent proof that 1 MW of electricity was generated from an eligible energy source. The RECs and SRECs can be traded and the owner of the RECs or SRECs can claim to have purchased renewable energy. RECs and SRECs are primarily sold under fixed contracts, and revenue for these contracts is recognized at a point in time, upon generation of the associated electricity. Any RECs or SRECs generated above contracted amounts are held in inventory, with the offset recorded as a decrease in operating expenses.

The Company applies the invoicing expedient to the electricity and capacity in the Renewable Energy Group contracts. As such, revenue is recognized at the amount to which the Company has the right to invoice for services performed. Revenue is recorded net of sales taxes.

(u)Foreign currency translation

AQN’s reporting currency is the U.S. dollar. Within these consolidated financial statements, the Company denotes any amounts denominated in Canadian dollars with “C$”, in Chilean pesos with “CLP” and in Chilean Unidad de Fomento with “CLF” immediately prior to the stated amounts.

Effective January 1, 2020, the functional currency of AQN, the non-consolidated parent entity, changed from the Canadian dollar to the U.S. dollar based on a balance of facts taking into consideration its operating, financing and investing activities. As a result of the entity's change of functional currency, changes were made to certain hedging relationships to mitigate the remaining Canadian dollar risk (note 24).

The Company’s Canadian operations have the Canadian dollar as their functional currency since the preponderance of operating, financing and investing transactions are denominated in Canadian dollars. Similarly, the Company's Chilean and Bermudian operations' functional currency is the Chilean peso and the Bermudian dollar, respectively. The financial statements of these operations are translated into U.S. dollars using the current rate method, whereby assets and liabilities are translated at the rate prevailing at the balance sheet date, and revenue and expenses are translated using average rates for the period. Unrealized gains or losses arising as a result of the translation of the financial statements of these entities are reported as a component of OCI and are accumulated in a component of equity on the consolidated balance sheets, and are not recorded in income unless there is a complete or substantially complete sale or liquidation of the investment.

(v)Income taxes

Income taxes are accounted for using the asset and liability method. Deferred tax assets and liabilities are recognized for the future tax consequences attributable to differences between the financial statement carrying amounts of assets and liabilities and their respective tax bases. Deferred tax assets and liabilities are measured using enacted tax rates expected to apply to taxable income in the years in which those temporary differences are expected to be recovered or settled. A valuation allowance is recorded against deferred tax assets to the extent that it is considered more likely than not that the deferred tax asset will not be realized. The effect on deferred tax assets and liabilities of a change in tax rates is recognized in earnings in the period that includes the date of enactment. Investment tax credits for the rate regulated operations are deferred and amortized as a reduction to income tax expense over the estimated useful lives of the properties. Investment tax credits along with other income tax credits in the non-regulated operations are treated as a reduction to income tax expense in the year the credit arises.

The organizational structure of AQN and its subsidiaries is complex and the related tax interpretations, regulations and legislation in the tax jurisdictions in which they operate are continually changing. As a result, there can be tax matters that have uncertain tax positions. The Company recognizes the effect of income tax positions only if those positions are more likely than not of being sustained. Recognized income tax positions are measured at the largest amount that is greater than 50% likely of being realized. Changes in recognition or measurement are reflected in the period in which the change in judgment occurs.


Algonquin Power & Utilities Corp.
Notes to the Consolidated Financial Statements
December 31, 2022 and 2021
(in thousands of U.S. dollars, except as noted and per share amounts)

1.Significant accounting policies (continued)

(w)Financial instruments and derivatives

Accounts receivable and notes receivable are measured at amortized cost. Long-term debt and preferred shares, Series C are measured at amortized cost using the effective interest method, adjusted for the amortization or accretion of premiums or discounts.

Transaction costs that are directly attributable to the acquisition of financial assets are accounted for as part of the asset’s carrying value at inception. Transaction costs related to a recognized debt liability are presented in the consolidated balance sheets as a direct deduction from the carrying amount of that debt liability, consistent with debt discounts and premiums. Costs of arranging the Company’s revolving credit facilities and intercompany loans are recorded in other assets. Deferred financing costs, premiums and discounts on long-term debt are amortized using the effective interest method while deferred financing costs relating to the revolving credit facilities and intercompany loans are amortized on a straight-line basis over the term of the respective instrument.

The Company uses derivative financial instruments as one method to manage exposures to fluctuations in exchange rates, interest rates and commodity prices. AQN recognizes all derivative instruments as either assets or liabilities on the consolidated balance sheets at their respective fair values. The fair value recognized on derivative instruments executed with the same counterparty under a master netting arrangement are presented on a gross basis on the consolidated balance sheets. The amounts that could net settle are not significant. The Company applies hedge accounting to some of its financial instruments used to manage its foreign currency risk, interest rate risk and price risk exposures associated with sales of generated electricity.

For derivatives designated in a cash flow hedge relationship, the change in fair value is recognized in OCI.

The amount recognized in AOCI is reclassified to earnings in the same period as the hedged cash flows affect earnings under the same line item in the consolidated statements of operations as the hedged item. If the hedging instrument no longer meets the criteria for hedge accounting, expires or is sold, terminated, exercised, or the designation is revoked, then hedge accounting is discontinued prospectively. The amount remaining in AOCI is transferred to the consolidated statements of operations in the same period that the hedged item affects earnings. If the forecasted transaction is no longer expected to occur, then the balance in AOCI is recognized immediately in earnings.

Foreign currency gain or loss on derivative or financial instruments designated as a hedge of the foreign currency exposure of a net investment in foreign operations that are effective as a hedge is reported in the same manner as the translation adjustment (in OCI) related to the net investment.

The Company’s electric distribution and thermal generation facilities enter into power and natural gas purchase contracts for load serving and generation requirements. These contracts meet the exemption for normal purchase and normal sales and, as such, are not required to be recorded at fair value as derivatives and are accounted for on an accrual basis. Counterparties are evaluated on an ongoing basis for non-performance risk to ensure it does not impact the conclusion with respect to this exemption.

(x)Fair value measurements

The Company utilizes valuation techniques that maximize the use of observable inputs and minimize the use of unobservable inputs to the extent possible. The Company determines fair value based on assumptions that market participants would use in pricing an asset or liability in the principal or most advantageous market. When considering market participant assumptions in fair value measurements, the following fair value hierarchy distinguishes between observable and unobservable inputs, which are categorized in one of the following levels:

•Level 1 Inputs: Unadjusted quoted prices in active markets for identical assets or liabilities accessible to the reporting entity at the measurement date.

•Level 2 Inputs: Other than quoted prices included in level 1, inputs that are observable for the asset or liability, either directly or indirectly, for substantially the full term of the asset or liability.

•Level 3 Inputs: Unobservable inputs for the asset or liability used to measure fair value to the extent that observable inputs are not available, thereby allowing for situations in which there is little, if any, market activity for the asset or liability at the measurement date.


Algonquin Power & Utilities Corp.
Notes to the Consolidated Financial Statements
December 31, 2022 and 2021
(in thousands of U.S. dollars, except as noted and per share amounts)

1.Significant accounting policies (continued)

(y)Commitments and contingencies

Liabilities for loss contingencies arising from environmental remediation, claims, assessments, litigation, fines, penalties and other sources are recorded when it is probable that a liability has been incurred and the amount can be reasonably estimated. Legal costs incurred in connection with loss contingencies are expensed as incurred.

(z)Use of estimates

The preparation of financial statements requires management to make estimates and assumptions that affect the reported amounts of assets and liabilities and disclosure of contingent assets and liabilities at the date of these consolidated financial statements and the reported amounts of revenue and expenses during the year. Actual results could differ from those estimates. During the years presented, management has made a number of estimates and valuation assumptions, including the useful lives and recoverability of property, plant and equipment, intangible assets and goodwill; the recoverability of notes receivable and long-term investments; the recoverability of deferred tax assets; assessments of unbilled revenue; pension and OPEB obligations; timing effect of regulated assets and liabilities; contingencies related to environmental matters; the fair value of assets and liabilities acquired in a business combination; and the fair value of financial instruments. These estimates and valuation assumptions are based on present conditions and management’s planned course of action, as well as assumptions about future business and economic conditions. Should the underlying valuation assumptions and estimates change, the recorded amounts could change by a material amount.

2. Recently issued accounting pronouncements

(a)Recently adopted accounting pronouncements

The Financial Accounting Standards Board (“FASB”) issued ASU 2021-05, Leases (Topic 842): Lessors — Certain Leases with Variable Lease Payments to address concerns relating to day-one losses for sales-type or direct financing leases with variable payments that do not depend on a reference index or rate. The update amends the lease classification requirements for lessors to align them with past practice under Topic 840, Leases. The adoption of this update did not have an impact on the consolidated financial statements.

The FASB issued ASU 2020-06, Debt — Debt with Conversion and Other Options (Subtopic 470-20) and Derivatives and Hedging — Contracts in Entity's Own Equity (Subtopic 815-40): Accounting for Convertible Instruments and Contracts in an Entity's Own Equity to address the complexity associated with accounting for certain financial instruments with characteristics of liabilities and equity. The number of accounting models for convertible debt instruments and convertible preferred stock is being reduced and the guidance has been amended for the derivatives scope exception for contracts in an entity's own equity to reduce form-over-substance-based accounting conclusions. The adoption of this update did not have an impact on the consolidated financial statements.

The FASB issued ASU 2020-04, Reference Rate Reform (Topic 848): Facilitation of the Effects of Reference Rate Reform on Financial Reporting, which provides optional expedients and exceptions to ease the potential burden in accounting for reference rate reform. The amendments apply to contracts, hedging relationships, and other transactions that reference LIBOR or another reference rate expected to be discontinued because of the reference rate reform. The FASB issued updates to Topic 848 in ASU 2022-06 and 2021-01 to clarify that the scope of Topic 848 includes derivatives affected by the discounting transition and extend the relief in Topic 848 to December 31, 2024, respectively. The adoption of this update did not have an impact on the consolidated financial statements.

(b)Recently issued accounting guidance not yet adopted

The FASB issued ASU 2022-04, Liabilities — Supplier Finance Programs (Subtopic 405-50): Disclosure of Supplier Finance Program Obligations, which require that a buyer in a supplier finance program disclose sufficient information about the program to allow a user of financial statements to understand the program’s nature, activity during the period, changes from period to period, and potential magnitude. The amendments in this update are effective for fiscal years beginning after December 15, 2022, including interim periods within those fiscal years, except for the amendment on roll forward information, which is effective for fiscal years beginning after December 15, 2023. Early adoption is permitted. The Company is currently assessing the relevant disclosure.


Algonquin Power & Utilities Corp.
Notes to the Consolidated Financial Statements
December 31, 2022 and 2021
(in thousands of U.S. dollars, except as noted and per share amounts)

3.Business acquisitions, development projects and disposition transactions

(a)Partial disposition of renewable assets

On December 29, 2022, the Company closed the sale of ownership interests in a portfolio of operating wind facilities in the United States and Canada. The transaction consisted of the sale of (1) a 49% ownership interest in three operating wind facilities in the United States totalling 551 MW of installed capacity: the Odell Wind Facility in Minnesota, the Deerfield Wind Facility in Michigan and the Sugar Creek Wind Facility in Illinois; and (2) an 80% ownership interest in the operating 175 MW Blue Hill Wind Facility in Saskatchewan. The Company retains control over the U.S. facilities. The Company will continue to oversee day-to-day operations and provide management services to each of the facilities.

The cash proceeds of $277,500 for the U.S. facilities, which continue to be consolidated, were recorded as non-controlling interest (subject to certain potential future post-closing adjustments). The investment in the Blue Hill Wind Facility continues to be recorded as an equity-method investee. Cash proceeds of C$108,610 were received for the Blue Hill Wind Facility (subject to certain potential future post-closing adjustments). A gain on disposition of $62,828 was recognized and included in gain on sale of renewable assets on the consolidated statements of operations.

(b)Pending acquisition of Kentucky Power Company and AEP Kentucky Transmission Company, Inc.

On October 26, 2021, Liberty Utilities Co., an indirect subsidiary of AQN, entered into an agreement (the “Kentucky Acquisition Agreement”) with American Electric Power Company, Inc. (“AEP”) and AEP Transmission Company, LLC to acquire Kentucky Power Company (“Kentucky Power”) and AEP Kentucky Transmission Company, Inc. (“Kentucky TransCo”) for a total purchase price of approximately $2,846,000, including the assumption of approximately $1,221,000 in debt (the “Kentucky Power Transaction”). On September 29, 2022, the parties entered into an amendment to the Kentucky Acquisition Agreement that, among other things, reduces the purchase price by $200,000.

Kentucky Power is a state rate-regulated electricity generation, distribution and transmission utility in 20 eastern Kentucky counties and operating under a cost of service framework. Kentucky TransCo is an electricity transmission business operating in the Kentucky portion of the transmission infrastructure that is part of the Pennsylvania – New Jersey – Maryland regional transmission organization, PJM Interconnection, L.L.C. Kentucky Power and Kentucky TransCo are both regulated by FERC.

Closing of the Kentucky Power Transaction remains subject to the satisfaction or waiver of certain conditions precedent, which include the approval of the Kentucky Power Transaction by FERC and clearance under the Hart-Scott-Rodino Antitrust Improvements Act of 1976 (as the clearance received previously has lapsed). On December 15, 2022, FERC issued an order denying, without prejudice, authorization for the proposed transaction. On February 14, 2023, a new application was filed with FERC for approval of the Kentucky Power Transaction. If the Kentucky Power Transaction has not closed by April 26, 2023, either party may, if certain requirements are met, terminate the Kentucky Acquisition Agreement in accordance with its terms.

(c)Acquisition of New York American Water Company, Inc.

Effective January 1, 2022, the Company completed the acquisition of New York American Water Company, Inc (subsequently renamed Liberty Utilities (New York Water) Corp. (“Liberty NY Water”)). Liberty NY Water is a regulated water and wastewater utility, serving customers in eight counties in southeastern New York.


Algonquin Power & Utilities Corp.
Notes to the Consolidated Financial Statements
December 31, 2022 and 2021
(in thousands of U.S. dollars, except as noted and per share amounts)

3.Business acquisitions, development projects and disposition transactions (continued)

(c)Acquisition of New York American Water Company, Inc. (continued)

A purchase price of $609,000 was paid for this acquisition. The acquisition related costs were expensed through the consolidated statement of operations (note 19). The following table summarizes the final allocation of the purchase price to the assets acquired and liabilities assumed when control was obtained.



Working capital	$	4,820
Property, plant and equipment (i)	499,252

Goodwill (ii)	116,254
Regulatory assets (iii)	65,621
Other assets	4,507

Pension and other post-employment benefits	(13,402)
Regulatory liabilities (iii)	(59,727)
Other liabilities	(8,028)
Total net assets acquired	$	609,297
Cash and cash equivalents acquired	49
Total net assets acquired, net of cash and cash equivalents	$	609,248

The determination of the fair value of assets acquired and liabilities assumed is based upon management’s estimates and certain assumptions.

i.Property, plant and equipment, consist of regulated water distribution infrastructure and wastewater collection and treatment facilities. They are amortized in accordance with regulatory requirements over the estimated useful life of the assets using the straight-line method. The weighted average useful life of Liberty NY Water’s assets is 64.74 years.

ii.Goodwill represents the excess of the purchase price over the aggregate fair value of net assets acquired. The contributing factors to the amount recorded as goodwill include future growth, potential synergies, and cost of savings in the delivery of certain shared administrative and other services. Goodwill is reported under the Regulated Services Group.

iii.The Company is subject to regulation by the New York State Public Service Commission (“NYPSC”), which has jurisdiction with respect to rates, service, accounting procedures, acquisitions, and other matters. Under ASC 980, regulatory assets and liabilities are recorded to the extent that they represent probable future revenue or expenses associated with certain charges or credits that will be recovered from or refunded to customers through the rate making process (note 7). As part of the approval of the acquisition of Liberty NY Water, a settlement agreement was approved which requires a full year of ownership prior to the filing of a new rate case. As a result, new rates would not come into effect until 2024.

Liberty NY Water was consolidated upon acquisition. In 2022, Liberty NY Water generated approximately $125,370 in revenue and $21,776 operating income.

(d)Acquisition of Mid-West Wind Facilities

In 2021, the Empire District Electric Company (“Empire Electric System”), a wholly owned subsidiary of the Company, acquired three wind farms generating up to 600 MW of wind energy located in Barton, Dade, Lawrence, and Jasper Counties in Missouri, and in Neosho County, Kansas (collectively, the “Mid-West Wind Facilities”). Up to that point, the Company had held an interest in the construction projects for the North Fork Ridge Wind Facility and the Kings Point Wind Facility. The Empire Electric System paid consideration to third-party developers of $97,760 and obtained control of the facilities. In 2021, subsequent to acquisition, the tax equity investors provided additional funding of $530,880 and third-party construction loans of $789,923 were repaid. The Company accounted for these transactions as asset acquisitions since substantially all of the fair value of gross assets acquired is concentrated in a group of similar identifiable assets.


Algonquin Power & Utilities Corp.
Notes to the Consolidated Financial Statements
December 31, 2022 and 2021
(in thousands of U.S. dollars, except as noted and per share amounts)

3.Business acquisitions, development projects and disposition transactions (continued)

(d)Acquisition of Mid-West Wind Facilities (continued)

The following table summarizes the allocation of the aggregate purchase price to the assets acquired and liabilities assumed at the acquisition dates.


	Mid-West Wind
Working capital	$	(28,630)
Property, plant and equipment	1,141,884
Long-term debt	(789,804)
Asset retirement obligation	(27,053)
Deferred tax liability	(4,566)
Other liabilities	(104,129)
Non-controlling interest (tax equity investors)	(29,141)
Total net assets acquired	158,561
Cash and cash equivalents	15,860
Net assets acquired, net of cash and cash equivalents	$	142,701

(e)Altavista Solar Facility

Up to April 2021, the Company held a 50% interest in Altavista Solar SponsorCo, LLC, an entity that indirectly owns an 80 MW solar power facility located in Campbell County, Virginia. In April 2021, the Company acquired the remaining 50% interest in Altavista Solar SponsorCo, LLC for $6,735 and as a result, obtained control of the facility. Subsequent to acquisition, the third-party construction loan of $122,024 was repaid. The Company accounted for the transaction as an asset acquisition since substantially all of the fair value of gross assets acquired is concentrated in a group of similar identifiable assets.

The following table summarizes the allocation of the purchase price to the assets acquired and liabilities assumed at the acquisition date of the solar facility.


	Altavista Solar
Working capital	$	870
Property, plant and equipment	138,343
Long-term debt	(122,024)
Deferred tax liability	(421)
Asset retirement obligation	(3,332)
Total net assets acquired	13,436
Cash and cash equivalents	33
Net assets acquired, net of cash and cash equivalents	$	13,403

(f)Maverick Creek Wind Facility and Sugar Creek Wind Facility

Up to January 2021, the Company held 50% equity interests in Maverick Creek Wind SponsorCo, LLC and AAGES Sugar Creek Wind, LLC (note 8). The two entities indirectly own 492 MW and 202 MW wind development projects in the state of Texas and Illinois (“Maverick Creek Wind Facility” and “Sugar Creek Wind Facility”), respectively. In January 2021, the Company acquired the remaining 50% interests in Maverick Creek Wind SponsorCo, LLC and AAGES Sugar Creek Wind, LLC for $43,797 in aggregate and obtained control of the facilities. An amount of $18,641 was withheld from the consideration for the acquisition of AAGES Sugar Creek Wind, LLC and remains payable upon the satisfaction of certain conditions. The Company accounted for the transactions as asset acquisitions since substantially all of the fair value of gross assets acquired is concentrated in a group of similar identifiable assets.


Algonquin Power & Utilities Corp.
Notes to the Consolidated Financial Statements
December 31, 2022 and 2021
(in thousands of U.S. dollars, except as noted and per share amounts)

3.Business acquisitions, development projects and disposition transactions (continued)

(f)Maverick Creek Wind Facility and Sugar Creek Wind Facility (continued)

The following table summarizes the allocation of the purchase price to the assets acquired and liabilities assumed at the acquisition date of the two wind facilities. The existing loans between the Company and the partnerships of $87,035 were treated as additional consideration incurred to acquire the partnerships.


	Maverick Creek and Sugar Creek
Working capital	$	(15,557)
Property, plant and equipment	1,062,613
Long-term debt	(855,409)
Asset retirement obligation	(23,402)
Deferred tax liability	(337)
Derivative instruments	7,575
Total net assets acquired	175,483
Cash and cash equivalents	4,241
Net assets acquired, net of cash and cash equivalents	$	171,242

Tax equity investors provided funding of $147,914 and $380,829 to the Sugar Creek Wind Facility and Maverick Creek Wind Facility, respectively, in 2021 and third-party construction loans of $284,829 and $570,578, respectively, were repaid subsequent to the acquisition of the remaining 50% interests in the facilities in 2021. A partial interest in the Sugar Creek Wind Facility was subsequently sold in December 2022 (note 3(a)).

4.Accounts receivable

Accounts receivable as of December 31, 2022 include unbilled revenue of $149,015 (December 31, 2021 - $102,693) from the Company’s regulated utilities. Accounts receivable as of December 31, 2022 are presented net of allowance for doubtful accounts of $24,857 (December 31, 2021 - $19,327).

5.Property, plant and equipment

Property, plant and equipment consist of the following:


2022
	Cost		Accumulated depreciation		Net book value
Renewable generation facilities	$	4,119,514	$	1,016,784	$	3,102,730
Utility plant	8,640,224		990,975		7,649,249
Land	113,153		—		113,153
Equipment	111,707		50,904		60,803
Construction in progress
Generation	196,287		—		196,287
Distribution and transmission	822,663		—		822,663

	$	14,003,548	$	2,058,663	$	11,944,885


Algonquin Power & Utilities Corp.
Notes to the Consolidated Financial Statements
December 31, 2022 and 2021
(in thousands of U.S. dollars, except as noted and per share amounts)

5.Property, plant and equipment (continued)


2021
	Cost		Accumulated depreciation		Net book value
Renewable generation facilities	$	4,187,197	$	751,219	$	3,435,978
Utility plant	7,468,236		780,537		6,687,699
Land	114,821		—		114,821
Equipment	101,971		56,464		45,507
Construction in progress
Generation	148,302		—		148,302
Distribution and transmission	610,139		—		610,139

	$	12,630,666	$	1,588,220	$	11,042,446

During the fourth quarter of 2022, the Company concluded that some assets in the Renewable Energy Group may not be recoverable due to declining forecasted energy prices in the Electric Reliability Council of Texas (“ERCOT”) market, mainly affecting the results of the Senate Wind Facility (which began commercial operations in 2012). Accordingly, the Company performed fair value analysis based on the income approach and recorded an impairment charge of $159,568 to reduce the carrying value of the Senate Wind Facility and other smaller assets from $259,942 to $100,374. Changes in assumptions of revenue forecasts, driven by expected production, basis difference and resulting spot prices, projected operating and capital expenditures would affect the estimated fair value.

Renewable generation facilities include cost of $111,192 (2021 - $114,868) and accumulated depreciation of $46,666 (2021 - $46,649) related to facilities under financing lease or owned by consolidated VIEs. Depreciation expense of facilities under finance leases was $1,489 (2021 - $1,716). Utility plant includes cost of $3,076 (2021 - $3,076) and accumulated depreciation of $2,041 (2021 - $1,665) related to assets under finance lease.

Utility plant includes cost of $2,033,391 (2021 - $2,018,039) and accumulated depreciation of $133,644 (2021 - $72,484) related to regulated generation assets.

For the year ended December 31, 2022, contributions received in aid of construction of $1,299 (2021 - $6,376) have been credited to the cost of the assets.

Interest and AFUDC capitalized to the cost of the assets in 2022 and 2021 are as follows:


	2022		2021
Interest capitalized on non-regulated property	$	4,762	$	3,313
AFUDC capitalized on regulated property:
Allowance for borrowed funds	6,040		3,208
Allowance for equity funds	1,901		829
	$	12,703	$	7,350


Algonquin Power & Utilities Corp.
Notes to the Consolidated Financial Statements
December 31, 2022 and 2021
(in thousands of U.S. dollars, except as noted and per share amounts)

6.Intangible assets and goodwill

Intangible assets consist of the following:


2022	Cost		Accumulated amortization		Net book value
Power sales contracts	$	56,926	$	42,818	$	14,108
Customer relationships	77,850		13,709		64,141
Interconnection agreements	10,098		1,851		8,247
Other (a)	10,338		151		10,187
	$	155,212	$	58,529	$	96,683


2021	Cost		Accumulated amortization		Net book value
Power sales contracts	$	58,112	$	43,118	$	14,994
Customer relationships	78,140		12,337		65,803
Interconnection agreements	15,072		1,721		13,351
Other (a)	10,968		—		10,968
	$	162,292	$	57,176	$	105,116

(a) Other includes brand names, water rights and miscellaneous intangibles

Estimated amortization expense for intangible assets for each of the next year is $2,580 and $2,572 for years two to five.

All goodwill pertains to the Regulated Services Group.


	2022		2021
Opening balance	$	1,201,244	$	1,208,390
Business acquisitions (note 3)	123,751		5,535

Foreign exchange	(4,416)		(12,681)

Closing balance	$	1,320,579	$	1,201,244

7.Regulatory matters

The operating companies within the Regulated Services Group are subject to regulation by the respective Regulators of the jurisdictions in which they operate. The respective Regulators have jurisdiction with respect to rate, service, accounting policies, issuance of securities, acquisitions and other matters. Except for ESSAL, these utilities operate under cost-of-service regulation as administered by these authorities. The Company’s regulated utility operating companies are accounted for under the principles of ASC 980, Regulated Operations. Under ASC 980, regulatory assets and liabilities that would not be recorded under U.S. GAAP for non-regulated entities are recorded to the extent that they represent probable future revenue or expenses associated with certain charges or credits that will be recovered from or refunded to customers through the rate setting process.


Algonquin Power & Utilities Corp.
Notes to the Consolidated Financial Statements
December 31, 2022 and 2021
(in thousands of U.S. dollars, except as noted and per share amounts)

7.Regulatory matters (continued)

At any given time, the Company can have several regulatory proceedings underway. The financial effects of these proceedings are reflected in the consolidated financial statements based on regulatory approval obtained to the extent that there is a financial impact during the applicable reporting period. The following regulatory proceedings were recently completed:


Utility	State, Province or Country	Regulatory Proceeding Type	Details
BELCO	Bermuda	General rate review	On March 18, 2022, the Regulatory Authority (“RA”) approved an annual increase of $22,800, for a revenue allowance of $224,056 and $226,160 in revenue for 2022 and 2023, respectively. The RA authorized a rate of return of 7.16%, comprised of a 62% equity and an 8.92% return on equity. The new rates are effective from April 1, 2022. In April, 2022, BELCO filed an appeal in the Supreme Court of Bermuda challenging the decisions made by the RA through the recent Retail Tariff Review.
Empire Electric	Missouri	General Rate Case (GRC) and Securitization	On April 6, 2022, the Missouri Public Service Commission (the "MPSC") approved an annual base rate increase of $35,516, as well as another $4,000 in revenues associated with the Empire Wind Facilities. The new rates became effective in June 2022. On January 19, 2022, Empire Electric filed a petition for securitization of the costs associated with the impact of the Midwest Extreme Weather Event. On March 21, 2022, Empire Electric filed a petition for securitization of the costs associated with the retirement of the Asbury generating plant. On August 18, 2022, and September 22, 2022, the MPSC issued and amended, respectively, a Report and Order authorizing Empire Electric to securitize approximately $290,383 in qualified extraordinary costs (Midwest Extreme Weather Event), energy transition costs (Asbury) and upfront financing costs associated with the proposed securitization. The amounts authorized by the securitization order are generally consistent with the costs deferred by the Company in relation to these matters. Empire Electric filed an appeal of the MPSC order on November 10, 2022 (note 7(a) and (b)). Briefing of the case is expected to be completed in April 2023.


Algonquin Power & Utilities Corp.
Notes to the Consolidated Financial Statements
December 31, 2022 and 2021
(in thousands of U.S. dollars, except as noted and per share amounts)

7.Regulatory matters (continued)


Utility	State, Province or Country	Regulatory Proceeding Type	Details
Empire Electric	Kansas	GRC	On May 27, 2021, Empire Electric submitted an abbreviated rate review seeking to recover costs associated with the addition of the Empire Wind Facilities, the retirement of Asbury and non-growth related plant investments since the 2019 rate review. In May 2022, the Commission approved the unanimous partial settlement resolving the rate treatment of the Asbury retirement and the non-wind investments resulting in a base rate decrease of $636, and granted Empire Electric's motion to withdraw its request to recover cost associated with the Empire Wind Facilities. New rates became effective in July 2022.
Empire District Gas Company	Missouri	GRC	In June 2022, the Commission approved an annual increase of $1,000 in base rate revenues. New rates became effective in August 2022.
Empire Electric	Oklahoma	GRC	On December 29, 2022 the Commission approved a joint stipulation and agreement filed by the Company and Staff authorizing an annual base rate revenue increase of $5,100.
New Brunswick Gas	Canada	GRC	On November 22, 2021, New Brunswick Gas filed its 2022 general rate application for a revenue decrease based on the Energy & Utilities Board's recent decision authorizing a capital structure of 45% equity and an ROE of 8.5%. In January 2022, New Brunswick Natural Gas appealed the Energy & Utilities Board's cost of capital decision. In May 2022, the Energy & Utilities Board issued a partial decision approving a decrease in annual revenues of $1,041 to become effective in July 2022. In June 2022, the Court of Appeal found in favour of New Brunswick Gas and remanded the cost of capital case back to the Energy & Utilities Board. On December 22, 2022 the Board issued a Final Order and approved an annual revenue increase of $1,265 based on an ROE of 9.8%. New rates became effective January 1, 2023.
Apple Valley Ranchos Water System	California	GRC	Subsequent to year-end, on February 3, 2023, the Commission issued a Final Order authorizing an annual revenue increase of $1,412. New rates are retroactive to July 1, 2022.
Park Water System	California	GRC	Subsequent to year-end, on February 3, 2023, the Commission issued a Final Order authorizing an annual revenue increase of $1,105. New rates are retroactive to July 1, 2022.


Algonquin Power & Utilities Corp.
Notes to the Consolidated Financial Statements
December 31, 2022 and 2021
(in thousands of U.S. dollars, except as noted and per share amounts)

7.Regulatory matters (continued)

Regulatory assets and liabilities consist of the following:


	December 31, 2022		December 31, 2021
Regulatory assets
Fuel and commodity cost adjustments (a)	$	388,294	$	339,900
Retired generating plant (b)	174,609		185,073
Rate adjustment mechanism (c)	136,198		117,309
Income taxes (d)	97,414		79,472
Deferred capitalized costs (e)	90,121		62,599
Pension and post-employment benefits (f)	80,736		134,287
Environmental remediation (g)	70,529		81,802
Wildfire mitigation and vegetation management (h)	66,156		35,726
Clean energy and other customer programs (i)	28,145		25,857
Asset retirement obligation (j)	27,172		26,810
Debt premium (k)	24,888		34,204
Cost of removal (l)	11,084		—
Rate review costs (m)	9,481		9,167
Long-term maintenance contract (n)	6,504		9,134
Other (o)	60,170		26,285
Total regulatory assets	$	1,271,501	$	1,167,625
Less: current regulatory assets	(190,393)		(158,212)
Non-current regulatory assets	$	1,081,108	$	1,009,413

Regulatory liabilities
Income taxes (d)	$	312,671	$	295,720
Cost of removal (l)	191,173		191,981
Pension and post-employment benefits (f)	68,085		34,468
Fuel and commodity cost adjustments (a)	24,991		18,175
Clean energy and other customer programs (i)	11,572		14,829

Rate adjustment mechanism (c)	343		3,316
Other	19,347		17,700
Total regulatory liabilities	$	628,182	$	576,189
Less: current regulatory liabilities	(69,865)		(65,809)
Non-current regulatory liabilities	$	558,317	$	510,380

As recovery of regulatory assets is subject to regulatory approval, if there were any changes in regulatory positions that indicate recovery is not probable, the related cost would be charged to earnings in the period of such determination. The Company generally does not earn a return on the regulatory balances except for carrying charges on fuel and commodity cost adjustments (a), rate adjustment mechanism (c), clean energy and other customer programs (i), and rate review costs of some jurisdictions (m). Carrying charges on regulatory balances are recognized on the consolidated statement of operations under Interest and other income (note 8) and are computed using only the debt component of the allowed returned.


Algonquin Power & Utilities Corp.
Notes to the Consolidated Financial Statements
December 31, 2022 and 2021
(in thousands of U.S. dollars, except as noted and per share amounts)

7.Regulatory matters (continued)

(a)Fuel and commodity cost adjustments

The revenue from the utilities includes a component that is designed to recover the cost of electricity and natural gas through rates charged to customers. To the extent actual costs of power or fuel purchased differ from power or fuel costs recoverable through current rates, that difference is deferred and recorded as a regulatory asset or liability on the consolidated balance sheets. These differences are reflected in adjustments to rates and recorded as an adjustment to cost of electricity and fuel in future periods ranging mostly from 6 to 24 months, subject to regulatory review. Derivatives are often utilized to manage the price risk associated with natural gas purchasing activities in accordance with the expectations of state regulators. The gains and losses associated with these derivatives (note 24(b)(i)) are recoverable through the commodity costs adjustment.

In February 2021, the Company's operations were impacted by extreme winter storm conditions experienced in Texas and parts of the central U.S. (“Midwest Extreme Weather Event”). As a result of the Midwest Extreme Weather Event, the Company incurred incremental commodity costs during the period of record high pricing and elevated consumption. The Company has commodity cost mechanisms that allow for the recovery of prudently incurred expenses.

In early 2022, pursuant to the securitization statute, Empire Electric sought authorization for the issuance of $221,646 in securitized utility tariff bonds associated with the Midwest Extreme Weather Event and $140,774, in securitized utility tariff bonds for its Asbury costs, which included $21,283 in asset retirement obligations, which are estimates of costs that Empire Electric will recover from the Asbury retirement but which have not yet been incurred. On April 27, 2022, the MPSC issued an order consolidating, for purposes of hearing, these two cases regarding the quantum financeable through securitization, which hearing was held the week of June 13, 2022. On August 18, 2022, and September 22, 2022, the MPSC issued and amended, respectively, a Report and Order authorizing Empire Electric to securitize $290,383 in qualified extraordinary costs (Midwest Extreme Weather Event), energy transition costs (Asbury) and upfront financing costs associated with the proposed securitization. The amounts authorized by the securitization order are generally consistent with the costs deferred by the Company in relation to these matters. Empire Electric filed a request for rehearing seeking reconsideration of the MPSC’s denial of recovery of five percent of the Midwest Extreme Weather Event costs, its calculation of accumulated deferred income taxes, and the exclusion of certain carrying charges associated with the Asbury plant, among other issues. On October 12, 2022, the MPSC denied all rehearing motions. Empire Electric appealed to the Missouri Court of Appeals - Western District on November 10, 2022. Briefing of the case is expected to be completed in April 2023.

(b)Retired generating plant

On March 1, 2020, the Company's 200 MW coal generation facility located in Asbury, Missouri, ceased operations. The Company transferred the remaining net book value of Asbury’s plant retired from plant in-service to a regulatory asset. The net book value that may be retained as an asset on the balance sheet for the retired plant is dependent upon amounts that may be recovered through regulated rates, including any return. An impairment charge, if any, would equal the difference between the remaining net book value of the asset and the present value of the future revenues expected from the asset. The ultimate valuation of the regulatory asset will be determined in future commission orders. The Company is also assessing the decommissioning requirements associated with the retirement of the facility.

Per commission orders in its jurisdictions, the Company is required to track the impact of Asbury's retirement on operating and capital expenses in Missouri for consideration in the next rate case. The Company recorded a regulatory liability for the estimated amount of revenues collected from customers for Asbury from March 1, 2020 to May 2022 that AQN determined was probable of refund. This regulatory liability did not include revenues collected related to the return on investment in Asbury as AQN determined that they were not probable of refund to customers based on the relevant facts and circumstances. AQN believes it is probable that the Asbury regulatory liability will be offset for recovery purposes against its unrecovered investment in Asbury and as a result, has netted its regulatory liability against its retired generation facilities regulatory asset.

As noted above under (a) Fuel and commodity cost adjustments, in March 2022, Empire Electric filed petitions for securitization of the impact of the Midwest Extreme Weather Event and the retirement of Asbury.


Algonquin Power & Utilities Corp.
Notes to the Consolidated Financial Statements
December 31, 2022 and 2021
(in thousands of U.S. dollars, except as noted and per share amounts)

7.Regulatory matters (continued)

(c)Rate adjustment mechanism

Revenue for CalPeco Electric System, New England Gas System, Midstates Gas system, EnergyNorth Gas System, Granite State Electric System, Peach State Gas System and BELCO is subject to a revenue decoupling mechanism approved by their respective regulator, which allows revenue decoupling from sales. As a result, the difference between delivery revenue calculated based on metered consumption and approved delivery revenue is recorded as a regulatory asset or liability to reflect future recovery or refund, respectively, from customers over periods ranging from one to five years. The revenue from BELCO includes a component that is designed to recover budgeted capital and operating expenses for the current year. To the extent actual capital and operating expenditures are lower than the budgeted amounts, 80% of the shortfall is refundable to customers and is recorded as a regulatory liability. Retroactive rate adjustments for services rendered but to be collected over a period not exceeding 24 months are accrued upon approval of the final order. The difference between New Brunswick Gas' regulated revenues and its regulated cost of service in past years is also recorded as a regulatory asset and is recovered on a straight-line basis over 26 years. The Liberty NY Water System has similar trackers which are recovered over periods ranging from one to two years.

(d)Income taxes

The income taxes regulatory assets and liabilities represent income taxes recoverable through future revenues required to fund flow-through deferred income tax liabilities over the life of the plants and amounts owed to customers for deferred taxes collected at a higher rate than the current statutory rates.

(e)Deferred capitalized costs

Deferred capitalized costs reflect deferred construction costs and fuel-related costs of specific generating facilities of the Empire Electric System. These amounts are being recovered over the life of the plants. The amount also includes capitalized operating and maintenance costs of New Brunswick Gas, and these amounts are being recovered at a rate of 2.43% annually.

In 2020, the Empire Electric System made an election under Missouri law to apply the plant-in-service accounting (“PISA”) regulatory mechanism, which permits the Empire Electric System to defer, on a Missouri jurisdictional basis, 85% of the depreciation expense and carrying costs at the applicable WACC on certain property, plant, and equipment placed in service after the election date and not included in base rates. The portions of regulatory asset balances that are not yet being recovered through rates shall include carrying costs at the WACC, plus applicable federal, state, and local income or excise taxes. Regulatory asset balances included in rate base shall be recovered in rates through a 20-year amortization beginning on the effective date of new rates. The Company recognizes the cost of debt on PISA deferrals as reduction of interest expense. The difference between the WACC and cost of debt will be recognized in revenue when recovery of such deferrals is reflected in customer rates.

(f)Pension and post-employment benefits

To the extent pension and OPEB costs incurred differ from the costs recoverable through current rates, that difference is deferred and recorded as a regulatory asset or liability as approved by the applicable Regulators and is recovered through rates over a period of 3 to 8 years. In addition, the annual movements in AOCI for pension and OPEB for Empire Electric System, Empire Gas Systems, St. Lawrence Gas System and Liberty NY Water System (note 10(a)) are reclassified to regulatory accounts in accordance with ASC 980, Regulated Operations. The balance is recovered through rates consistent with the treatment of OCI under ASC 712, Compensation Non-retirement Post-employment Benefits and ASC 715, Compensation Retirement Benefits. As part of certain business acquisitions, the regulators authorized a regulatory asset or liability being set up for the amounts of pension and post-employment benefits that had not yet been recognized in net periodic cost and were presented as AOCI prior to the acquisition. These balances are recovered through rates over the future service years of the employees (an average of 10 years) or consistent with the treatment of OCI under ASC 712, Compensation Non-retirement Post-employment Benefits and ASC 715, Compensation Retirement Benefits before the transfer to regulatory asset occurred.


Algonquin Power & Utilities Corp.
Notes to the Consolidated Financial Statements
December 31, 2022 and 2021
(in thousands of U.S. dollars, except as noted and per share amounts)

7.Regulatory matters (continued)

(g)Environmental remediation

Actual expenditures incurred for the clean-up of certain former natural gas manufacturing facilities (note 12(d)) are recovered through rates over a period of 7 years and are subject to an annual cap.

(h)Wildfire mitigation and vegetation management

The regulatory asset includes incremental wildfire liability insurance premium costs approved for tracking in the Company's California operations as well as the difference between actual and adopted spending related to dead trees program, to prevent future forest fires and general vegetation management. The assets are recovered over two years.

(i)Clean energy and other customer programs

The regulatory asset for clean energy and customer programs includes initiatives related to solar rebate applications processed and resulting rebate-related costs. The amount also includes other energy efficiency programs. The assets are generally included in rate base and recovered over periods of six to ten years.

(j)Asset retirement obligation

Asset retirement obligations are recorded for legally required removal costs of property, plant and equipment. The costs of retirement of assets as well as the on-going liability accretion and asset depreciation expense are expected to be recovered through rates once expenditures are made.

(k)Debt premium

Debt premium on acquired debt is recovered as a component of the weighted average cost of debt.

(l)Cost of removal

Rates charged to customers cover for costs that are expected to be incurred in the future to retire the utility plant. A regulatory liability (or asset) tracks the amounts that have been collected from customers net of costs incurred to date.

(m)Rate review costs

The cost to file, prosecute and defend rate review applications is referred to as rate review costs. These costs are capitalized and amortized over the period of rate recovery granted by the Regulator ranging from one to five years

(n)Long-term maintenance contract

To the extent actual costs of long-term maintenance incurred for one of Empire Electric System's power plants differ from the costs recoverable through current rates, that difference is generally included in rate base and recovered over five years.

(o) Other

The Company’s regulated utilities incur other miscellaneous costs such as storm costs, property taxes, financing costs, and equipment costs, which are probable of recovery under existing mechanisms.


Algonquin Power & Utilities Corp.
Notes to the Consolidated Financial Statements
December 31, 2022 and 2021
(in thousands of U.S. dollars, except as noted and per share amounts)

8.Long-term investments

Long-term investments consist of the following:


	December 31, 2022		December 31, 2021
Long-term investments carried at fair value
Atlantica (a)	$	1,268,140	$	1,750,914

Atlantica Yield Energy Solutions Canada Inc. (b)	74,083		95,246
Other	1,984		2,296
	$	1,344,207	$	1,848,456

Other long-term investments
Equity-method investees (c)	$	381,802	$	433,850
Development loans receivable from equity-method investees (d)	52,923		31,468
San Antonio Water System and other (e)	27,600		30,508
	$	462,325	$	495,826

Fair value change, income (loss) and impairment expense related to long-term investments from the years ended December 31 is as follows:


	Year ended December 31,
		2022		2021
Fair value gain (loss) on investments carried at fair value
Atlantica		$	(482,774)	$	(107,030)

Atlantica Yield Energy Solutions Canada Inc.		(16,018)		(15,915)
Other		(333)		526
		$	(499,125)	$	(122,419)
Dividend and interest income from investments carried at fair value
Atlantica		$	86,664	$	83,971
Atlantica Yield Energy Solutions Canada Inc.		20,443		17,222
Other		36		330
		$	107,143	$	101,523
Other long-term investments
Equity method loss (c)		$	(21,416)	$	(26,337)
Impairment of equity-method investee (c)		(75,910)		—
Interest and other income		24,102		20,776
		$	(73,224)	$	(5,561)
Fair value change, income (loss) and impairment expense related to long-term investments		$	(465,206)	$	(26,457)

(a)Investment in Atlantica

Liberty (AY Holdings) B.V. (“AY Holdings”), an entity controlled and consolidated by AQN, has a share ownership in Atlantica Sustainable Infrastructure PLC (“Atlantica”) of approximately 42% (2021 - 44%). AQN has the flexibility, subject to certain conditions, to increase its ownership of Atlantica up to 48.5%. The total cost for the Atlantica shares as of December 31, 2022 is $1,167,444 (2021 - $1,167,444).

The Company has elected the fair value option under ASC 825, Financial Instruments to account for its investment in Atlantica, with changes in fair value reflected in the consolidated statements of operations.


Algonquin Power & Utilities Corp.
Notes to the Consolidated Financial Statements
December 31, 2022 and 2021
(in thousands of U.S. dollars, except as noted and per share amounts)

8.Long-term investments (continued)

(b)Investment in AYES Canada

AQN and Atlantica own Atlantica Yield Energy Solutions Canada Inc. (“AYES Canada”), a vehicle to channel co-investment opportunities in which Atlantica holds the majority of voting rights. AYES Canada invested in Windlectric Inc. (“Windlectric”). The investment by AYES Canada in Windlectric is presented as a non-controlling interest held by a related party (notes 17).

AYES Canada is considered to be a VIE based on the disproportionate voting and economic interests of the shareholders. Atlantica is considered to be the primary beneficiary of AYES Canada. Accordingly, AQN's investment in AYES Canada is considered an equity method investment. Under the AYES Canada shareholders agreement, AQN has the option to exchange approximately 3,500,000 shares of AYES Canada into ordinary shares of Atlantica on a one-for-one basis, subject to certain conditions. Consistent with the treatment of the Atlantica shares, the Company has elected the fair value option under ASC 825, Financial Instruments to account for its investment in AYES Canada, with changes in fair value reflected in the consolidated statements of operations.

As at December 31, 2022, the Company's maximum exposure to loss is $74,083 (2021 - $95,246), which represents the fair value of the investment.

(c)Equity-method investees

The Renewable Energy Group has non-controlling interests in operating renewable energy facilities and projects under construction with a total carrying value of $310,103 (2021 - $375,460). The Regulated Services Group has non-controlling interest of $56,199 (2021 - 37,492) in a power transmission line project under construction and other non-regulated operating entities owned by its utilities. The Liberty Development JV Inc. platform for non-regulated renewable energy, water and other sectors has a carrying value of $15,500 and (2021 - $20,898) is reported under Corporate.

Operating entities: The Company has interests in the operating entities listed below. The Company is not considered the primary beneficiary as the two partners have joint control and all key decisions must be unanimous. As such, the Company accounts for its interests using the equity method.


	Economic interest		Capacity
Texas Coastal Wind Facilities	51	%	861 MW
Blue Hill Wind Facility	20	%	175 MW
Red Lily Wind Facility	75	%	26.4 MW
Val-Eo Wind Facility	50	%	24 MW

During 2021, the Company acquired a 51% interest in four wind facilities located in Texas (“Texas Coastal Wind Facilities”) for $344,883. All facilities achieved commercial operations in 2021. As at December 31, 2022, the Company had issued $113,630 (2021 - $119,750) in letters of credit and guarantees of performance obligations under energy purchase agreements and decommissioning obligations on behalf of the Texas Coastal Wind Facilities. During the fourth quarter of 2022, the Company concluded that primarily as a result of continued challenges with congestion at the facilities, the carrying value of the interest in the Texas Coastal Wind Facilities was other-than-temporarily impaired. Accordingly, the Company performed a fair value analysis based on the income approach and recorded an impairment charge of $75,910 to reduce the carrying value of its equity investment in the Texas Coastal Wind Facilities from $282,726 to 206,816. Changes in assumptions of revenue forecasts, driven by expected production, basis difference and resulting spot prices, projected operating and capital expenditures would affect the estimated fair value.

Development: Pursuant to an agreement between AQN and funds managed by the Infrastructure and Power strategy of Ares Management, LLC (“Ares”), in November 2021 Ares became AQN’s new partner in its non-regulated development platform for renewable energy, water and other sectors as both parties contributed cash or assets of $19,688 to Liberty Development JV Inc. The Company is not considered the primary beneficiary as the two partners have joint control and all key decisions must be unanimous. As such, the Company accounts for its interests using the equity method.


Algonquin Power & Utilities Corp.
Notes to the Consolidated Financial Statements
December 31, 2022 and 2021
(in thousands of U.S. dollars, except as noted and per share amounts)

8.Long-term investments (continued)

(c)Equity-method investees (continued)

Construction: The Renewable Energy Group has 50% equity interests in several wind and solar power electric construction projects. AQN and Ares have formed Liberty Construction (US) JV LLC (“Liberty Construction JV”) to jointly construct projects under the Renewable Energy Group. During the year, the Company contributed several projects to joint entities. The transfers resulted in a gain of $nil (2021 - $26,182). The Company holds an option to acquire the remaining interest in most construction projects at a pre-agreed price. The Company is not considered the primary beneficiary as the partners have joint control and all key decisions must be unanimous. As such, the Company accounts for its interests using the equity method.

Changes in the carrying value of equity method investees were as follows:


	2022		2021
Carrying value, January 1	$	433,850	$	186,452
Additional Investments	110,441		418,434
Net loss attributable to AQN	(21,416)		(26,337)
Other comprehensive income (loss) attributable to AQN (a)	(67,110)		7,733
Operating projects bought back by AQN	—		(129,075)
Dividend received	(1,183)		(2,981)
Impairment	(75,910)		—
Reclassification during the period (note 8(e))	—		(25,634)
Other	3,130		5,258
Carrying value, December 31	$	381,802	$	433,850

(a) Other comprehensive loss represents the Company’s proportion of the change in fair value, recorded in OCI at the investee level, on energy derivative financial instruments designated as a cash flow hedge,

Summarized combined information for AQN's equity method investees as at December 31 is as follows:


	2022		2021
Total assets	$	2,740,132	$	2,126,934
Total liabilities	1,507,079		945,971
Net assets	1,233,053		1,180,963
AQN's ownership interest in the entities	332,663		327,555
Difference between investment carrying amount and underlying equity in net assets(a)	49,139		106,295
Total carrying value	$	381,802	$	433,850

(a) The difference between the investment carrying amount and the underlying equity in net assets relates primarily to interest capitalized while the projects are under construction, the fair value of guarantees provided by the Company in regards to the investments, development fees and transaction costs.


Algonquin Power & Utilities Corp.
Notes to the Consolidated Financial Statements
December 31, 2022 and 2021
(in thousands of U.S. dollars, except as noted and per share amounts)

8.Long-term investments (continued)

(c)Equity-method investees (continued)

Summarized combined information for AQN's equity method investees for the year ended December 31 (presented at 100%) is as follows:


	2022		2021
Revenue	$	65,025	$	20,262
Net loss	$	(31,070)	$	(46,293)
Other comprehensive income (loss) (a)	$	(130,729)	$	15,177
Net loss attributable to AQN	$	(21,416)	$	(26,337)
Other comprehensive loss attributable to AQN (a)	$	(67,110)	$	7,733

Except for Liberty Global Energy Solutions B.V. (formerly Abengoa-Algonquin Global Energy Solutions B.V.) (“Liberty Global Energy Solutions”), Liberty Development JV Inc. and all construction projects are considered VIEs due to the level of equity at risk and the disproportionate voting and economic interests of the shareholders. The Company has committed loan and credit support facilities with some of its equity investees. During construction, the Company has agreed to provide cash advances and credit support for the continued development and construction of the equity investees' projects. As of December 31, 2022, the Company had issued letters of credit and guarantees of performance obligations: under a security of performance for a development opportunity; wind turbine or solar panel supply agreements; engineering, procurement, and construction agreements; interconnection agreements; energy purchase agreements; renewable energy credit agreements; and construction loan agreements. The fair value of the support provided recorded as at December 31, 2022 amounts to $8,824 (2021 - $4,612).

Summarized combined information for AQN's VIEs as at December 31 is as follows:


	2022		2021
AQN's maximum exposure in regards to VIEs
Carrying amount	$	122,752	$	86,202
Development loans receivable (d)	52,923		31,468
Performance guarantees and other commitments on behalf of VIEs	658,224		409,232
	$	833,899	$	526,902

The commitments are presented on a gross basis assuming no recoverable value in the assets of the VIEs. The majority of the amounts committed on behalf of VIEs in the above relate to wind turbine or solar panel supply agreements as well as engineering, procurement, and construction agreements.

(d)Development loans receivable from equity investees

The Renewable Energy Group has committed loan and credit support facilities with some of its equity investees. During construction, the Company has agreed to provide cash advances and credit support (in the form of letters of credit, escrowed cash, guarantees or indemnities) in amounts necessary for the continued development and construction of the equity investees' projects. The loans generally mature on the twelfth anniversary of the development agreement or commercial operation date.

(e)San Antonio Water System and other

The Company no longer has significant influence over its 20% interest in the San Antonio Water System (“SAWS”), and therefore has discontinued the equity method of accounting in 2021. The investment is accounted for using the cost method prospectively.


Algonquin Power & Utilities Corp.
Notes to the Consolidated Financial Statements
December 31, 2022 and 2021
(in thousands of U.S. dollars, except as noted and per share amounts)

9.Long-term debt

Long-term debt consists of the following:


Borrowing type	Weighted average coupon		Maturity	Par value		December 31, 2022		December 31, 2021
Senior unsecured revolving credit facilities (a)	—		2024-2027	N/A		$	351,786	$	368,806
Senior unsecured bank credit facilities and delayed draw term facility (b)	—		2023-2031	N/A		773,643		141,956
Commercial paper	—		2023	N/A		407,000		338,700
U.S. dollar borrowings
Senior unsecured notes (Green Equity Units) (c)	1.18	%	2026	$	1,150,000	1,142,814		1,140,801
Senior unsecured notes (d)	3.39	%	2023-2047	$	1,505,000	1,496,101		1,689,792
Senior unsecured utility notes	6.34	%	2023-2035	$	142,000	154,271		155,571
Senior secured utility bonds	4.71	%	2026-2044	$	556,209	554,822		558,177

Canadian dollar borrowings
Senior unsecured notes (e)	3.68	%	2027-2050	C$	1,200,000	882,899		1,099,403
Senior secured project notes	10.21	%	2027	C$	20,349	15,024		18,344
Chilean Unidad de Fomento borrowings
Senior unsecured utility bonds	4.05	%	2028-2040	CLF	1,637	77,206		77,963
						$	5,855,566	$	5,589,513
Subordinated U.S. dollar borrowings
Subordinated unsecured notes (f)	5.25	%	2082	C$	400,000	291,238		—
Subordinated unsecured notes (f)	5.56	%	2078-2082	$	1,387,500	1,365,213		621,862
						$	7,512,017	$	6,211,375
Less: current portion						(423,274)		(356,397)
						$	7,088,743	$	5,854,978

Short-term obligations of $705,386 that are expected to be refinanced using the long-term credit facilities are presented as long-term debt.

Long-term debt issued at a subsidiary level (project notes or utility bonds) relating to a specific operating facility is generally collateralized by the respective facility with no other recourse to the Company. Long-term debt issued at a subsidiary level whether or not collateralized generally has certain financial covenants, which must be maintained on a quarterly basis. Non-compliance with the covenants could restrict cash distributions/dividends to the Company from the specific facilities.


Algonquin Power & Utilities Corp.
Notes to the Consolidated Financial Statements
December 31, 2022 and 2021
(in thousands of U.S. dollars, except as noted and per share amounts)

9.Long-term debt (continued)

The following table sets out the bank credit facilities available to AQN and its operating groups as at December 31, 2022:



	December 31, 2022		December 31, 2021
Revolving and term credit facilities	$	4,513,300	$	3,217,000
Funds drawn on facilities/ commercial paper issued	(1,532,500)		(849,600)
Letters of credit issued	(465,200)		(317,200)
Liquidity available under the facilities	2,515,600		2,050,200
Undrawn portion of uncommitted letter of credit facilities	(226,900)		(224,000)
Cash on hand	57,623		125,157
Total liquidity and capital reserves	$	2,346,323	$	1,951,357

Recent financing activities:

(a)Senior unsecured revolving credit facilities

Regulated Services Group

On April 29, 2022, the Regulated Services Group entered into two new senior unsecured revolving credit facilities: a $1,000,000 senior unsecured revolving credit facility with an initial maturity date of April 29, 2027 (the “Long-Term Regulated Services Credit Facility”) and a $500,000 short-term senior unsecured revolving credit facility maturing originally on March 31, 2023 and extended to February 28, 2024, subsequent to year-end. Subject to the terms and conditions therein, the Long-Term Regulated Services Credit Facility may be extended for two additional one-year periods. In conjunction with the new facilities, the Regulated Services Group’s $500,000 senior unsecured syndicated revolving credit facility was cancelled.

On December 23, 2022, the Regulated Services Group amended and restated its $75,000 senior unsecured revolving credit facility in Bermuda with a new maturity date of December 31, 2024. On June 24, 2022, the Regulated Services Group entered into a new $25,000 senior unsecured bilateral revolving credit facility in Bermuda that matures on June 24, 2024.

Renewable Energy Group

On July 22, 2022, the Renewable Energy Group amended and restated its $500,000 senior unsecured syndicated revolving credit facility (the "Renewable Energy Credit Facility") with a new maturity date of July 22, 2027. Subject to the terms and conditions therein, the Renewable Energy Credit Facility may be extended for additional one-year periods.

On July 22, 2022, the Renewable Energy Group entered into a new $250,000 uncommitted bilateral letter of credit facility. On November 8, 2022, the Renewable Energy Group's $350,000 uncommitted letter of credit facility was amended and restated with a new maturity date of June 30, 2024.

(b)Senior unsecured bank credit facilities

On November 30, 2022, the Regulated Services Group amended and restated its $1,100,000 senior unsecured delayed draw term facility ("the "Regulated Services Delayed Draw Term Facility") with the new maturity date of November 29, 2023.

(c)U.S dollar senior unsecured notes (Green Equity Units)

In June 2021, the Company sold 23,000,000 equity units (the “Green Equity Units”) for total gross proceeds of $1,150,000. Each Green Equity Unit was issued in a stated amount of $50, at issuance, consisted of a contract to purchase AQN common shares (the “share purchase contract”) and a 5% undivided beneficial ownership interest in a remarketable senior note of AQN due June 15, 2026, issued in the principal amount of $1,000.


Algonquin Power & Utilities Corp.
Notes to the Consolidated Financial Statements
December 31, 2022 and 2021
(in thousands of U.S. dollars, except as noted and per share amounts)

9.Long-term debt (continued)

Recent financing activities (continued):

(c)U.S dollar senior unsecured notes (Green Equity Units) (continued)

Total annual distributions on the Green Equity Units are at a rate of 7.75%, consisting of interest on the notes (1.18% per year) and payments under the share purchase contract (6.57% per year). The interest rate on the notes will be reset following a successful marketing, which would occur in 2024. The present value of the contract adjustment payments was estimated at $222,378 and is recorded against additional paid-in capital (“APIC”) to the extent of the APIC balance and against retained earnings (deficit) for the remainder. The corresponding amount of $222,378 was recorded in other liabilities and is accreted over the three-year period (note 12(a)).

Each share purchase contract requires the holder to purchase by no later than June 15, 2024 for a price of $50 in cash, a number of AQN common shares (“common shares”) based on the applicable market value to be determined using the volume-weighted average price of the common shares over a 20-day trading period ending June 14, 2024. The minimum settlement rate under the purchase contracts is 2.7778 common shares, which is approximately equal to the $50 stated amount per Green Equity Unit, divided by the threshold appreciation price of $18 per common share. The maximum settlement rate under the purchase contracts is 3.3333 common shares, which is approximately equal to the $50 stated amount per Green Equity Unit, divided by $15 per common share.

The common share purchase obligation of holders of Green Equity Units will be satisfied by the proceeds raised from a successful remarketing of the notes, unless a holder has elected to settle with separate cash. Holders’ beneficial ownership interest in each note has been pledged to AQN to secure the holders' obligation to purchase common shares under the related share purchase contract.

Prior to the issuance of common shares, the share purchase contracts, if dilutive, will be reflected in the Company's diluted earnings per share calculations using the treasury stock method.

(d)U.S. dollar senior unsecured notes

On April 30, 2022, the Company repaid a $80,000 senior unsecured note on its maturity.

On August 1, 2022, the Company repaid a $115,000 senior unsecured note on its maturity.

Subsequent to year end, the Company repaid a $15,000 senior unsecured note on its maturity.

(e)Canadian dollar senior unsecured notes

On February 15, 2022, the Company repaid a C$200,000 senior unsecured note on its maturity. On February 15, 2021, the Renewable Energy Group repaid a C$150,000 unsecured note upon its maturity. Concurrent with the repayments, the Renewable Energy Group unwound and settled the related cross-currency fixed-for-fixed interest rate swap (note 24(b)(iii)).

On April 9, 2021, the Renewable Energy Group issued C$400,000 senior unsecured debentures bearing interest at 2.85% with a maturity date of July 15, 2031. The notes were sold at a price of C$999.92 per C$1,000.00 principal amount. Concurrent with the offering, the Renewable Energy Group entered into a fixed-for-fixed cross-currency interest rate swap to convert the Canadian-dollar-denominated coupon and principal payments from the offering into U.S. dollars (note 24(b)(iii)).


Algonquin Power & Utilities Corp.
Notes to the Consolidated Financial Statements
December 31, 2022 and 2021
(in thousands of U.S. dollars, except as noted and per share amounts)

9.Long-term debt (continued)

Recent financing activities (continued):

(f)Subordinated unsecured notes

On January 18, 2022, the Company closed (i) an underwritten public offering in the United States (the “U.S. Offering”) of $750,000 aggregate principal amount of 4.75% fixed-to-fixed reset rate junior subordinated notes series 2022-B due January 18, 2082 (the “U.S. Notes”); and (ii) an underwritten public offering in Canada (the “Canadian Offering” and, together with the U.S. Offering, the “Offerings”) of C$400,000 (approximately $320,000) aggregate principal amount of 5.25% fixed-to-fixed reset rate junior subordinated notes series 2022-A due January 18, 2082 (the “Canadian Notes” and, together with the U.S. Notes, the “Notes”). Concurrent with the pricing of the Offerings, the Company entered into a cross currency interest rate swap to convert the Canadian dollar denominated proceeds from the Canadian Offering into U.S. dollars, and a forward starting swap to fix the interest rate for the second five year term of the U.S. Notes, resulting in an anticipated effective interest rate to the Company of approximately 4.95% throughout the first ten-year period of the Notes.

As of December 31, 2022, the Company had accrued $70,274 in interest expense (2021 - $49,806). Interest expense for the years ended December 31 consists of the following:


	2022		2021
Long-term debt	$	261,535	$	217,123
Commercial paper, credit facility draws and related fees	43,015		17,065
Accretion of fair value adjustments	(16,547)		(18,174)
Capitalized interest and AFUDC capitalized on regulated property	(10,802)		(6,521)
Other	1,373		61
	$	278,574	$	209,554

Principal payments due in the next five years and thereafter are as follows:


2023		2024		2025		2026		2027		Thereafter		Total
$	1,128,660	$	359,371	$	45,262	$	1,265,711	$	719,144	$	4,019,166	$	7,537,314

10.Pension and other post-employment benefits

The Company provides defined contribution pension plans to substantially all of its employees. The Company’s contributions for 2022 were $12,126 (2021 - $10,836).

The Company provides a defined benefit cash balance pension plan under which employees are credited with a percentage of base pay plus a prescribed interest rate credit. In conjunction with the utility acquisitions, the Company also assumes defined benefit pension, SERP and OPEB plans for qualifying employees in the related acquired businesses. The legacy plans are non-contributory defined pension plans covering substantially all employees of the acquired businesses. Benefits are based on each employee’s years of service and compensation. The Company permanently freezes the accrual of benefits for participants in legacy plans. Thereafter, employees accrue benefits under the Company’s cash balance plan. The OPEB plans provide health care and life insurance coverage to eligible retired employees. Eligibility is based on age and length of service requirements and, in most cases, retirees must cover a portion of the cost of their coverage.


Algonquin Power & Utilities Corp.
Notes to the Consolidated Financial Statements
December 31, 2022 and 2021
(in thousands of U.S. dollars, except as noted and per share amounts)

10.Pension and other post-employment benefits (continued)

(a)Net pension and OPEB obligation

The following table sets forth the projected benefit obligations, fair value of plan assets, and funded status of the Company’s plans as of December 31:


	Pension benefits				OPEB
	2022		2021		2022		2021
Change in projected benefit obligation
Projected benefit obligation, beginning of year	$	765,618	$	834,913	$	292,646	$	306,524
Projected benefit obligation assumed from business combination	87,933		—		5,195		—

Plan Settlements	(112)		(1,294)		—		—

Service cost	16,309		14,673		6,277		7,307
Interest cost	24,787		20,676		9,146		8,048
Actuarial gain	(198,074)		(36,597)		(82,991)		(18,977)
Contributions from retirees	—		—		2,220		2,040

Plan amendments	—		237		(2,452)		310
Medicare Part D	—		—		367		373
Benefits paid	(68,197)		(66,800)		(13,078)		(12,979)
Foreign exchange	(129)		(190)		—		—
Projected benefit obligation, end of year	$	628,135	$	765,618	$	217,330	$	292,646
Change in plan assets
Fair value of plan assets, beginning of year	648,864		629,157		192,375		176,616
Plan assets acquired in business combination	74,532		—		8,577		—
Actual return on plan assets	(109,118)		58,721		(30,105)		15,200
Employer contributions	23,296		29,058		11,811		11,178

Plan Settlements	(112)		(1,294)		—		—
Contributions from retirees	—		—		2,220		1,988
Medicare Part D subsidy receipts	—		—		367		372
Benefits paid	(68,197)		(66,800)		(13,078)		(12,979)
Foreign exchange	(10)		22		—		—
Fair value of plan assets, end of year	$	569,255	$	648,864	$	172,167	$	192,375
Unfunded status	$	(58,880)	$	(116,754)	$	(45,163)	$	(100,271)
Amounts recognized in the consolidated balance sheets consist of:
Non-current assets (note 11)	12,264		11,751		14,218		11,879
Current liabilities	(1,907)		(1,902)		(3,039)		(699)
Non-current liabilities	(69,237)		(126,603)		(56,342)		(111,451)
Net amount recognized	$	(58,880)	$	(116,754)	$	(45,163)	$	(100,271)

The accumulated benefit obligation for the pension and OPEB plans was $815,589 and $1,080,685 as of December 31, 2022 and 2021, respectively.


Algonquin Power & Utilities Corp.
Notes to the Consolidated Financial Statements
December 31, 2022 and 2021
(in thousands of U.S. dollars, except as noted and per share amounts)

10.Pension and other post-employment benefits (continued)

(a)Net pension and OPEB obligation (continued)

Information for pension and OPEB plans with an accumulated benefit obligation in excess of plan assets:


	Pension				OPEB
	2022		2021		2022		2021
Accumulated benefit obligation	$	413,041	$	489,043	$	198,463	$	274,649
Fair value of plan assets	$	364,229	$	396,679	$	139,368	$	162,592

Information for pension and OPEB plans with a projected benefit obligation in excess of plan assets:


	Pension				OPEB
	2022		2021		2022		2021
Projected benefit obligation	$	489,140	$	580,841	$	198,463	$	274,649
Fair value of plan assets	$	417,994	$	452,333	$	139,368	$	162,592

(b)Pension and post-employment actuarial changes


Change in AOCI, before tax	Pension				OPEB
	Actuarial losses (gains)		Past service gains		Actuarial losses (gains)		Past service losses (gains)
Balance, January 1, 2021	$	57,231	$	(5,306)	$	(4,299)	$	—

Additions to AOCI	(59,754)		237		(24,126)		(24)
Amortization in current period	(13,130)		1,626		(2,021)		334
Amortization due to plan settlements	(210)		—		—		—
Reclassification to regulatory accounts	31,670		(752)		14,816		—
Balance, December 31, 2021	$	15,807	$	(4,195)	$	(15,630)	$	310

Additions to AOCI	(47,473)		—		(41,527)		(24)
Amortization in current period	(3,429)		1,584		56		(2,476)
Amortization due to plan settlements	15		—		—		—
Reclassification to regulatory accounts	34,409		(752)		23,551		—
Balance, December 31, 2022	$	(671)	$	(3,363)	$	(33,550)	$	(2,190)

The movements related to pension and OPEB in AOCI for Empire Electric System, Empire Gas Systems, St. Lawrence Gas System and Liberty NY Water System are reclassified to regulatory accounts since it is probable the unfunded amount of these plans will be afforded rate recovery (note 7(f)).


Algonquin Power & Utilities Corp.
Notes to the Consolidated Financial Statements
December 31, 2022 and 2021
(in thousands of U.S. dollars, except as noted and per share amounts)

10.Pension and other post-employment benefits (continued)

(c)Assumptions

Weighted average assumptions used to determine net benefit obligation for 2022 and 2021 were as follows:


	Pension benefits				OPEB
	2022		2021		2022		2021
Discount rate	5.48	%	2.94	%	5.49	%	3.00	%
Interest crediting rate (for cash balance plans)	4.50	%	4.00	%	N/A		N/A
Rate of compensation increase	3.70	%	4.00	%	N/A		N/A
Health care cost trend rate
Before age 65					6.00	%	5.88	%
Age 65 and after					6.00	%	5.88	%
Assumed ultimate medical inflation rate					4.75	%	4.75	%
Year in which ultimate rate is reached					2033		2031

The mortality assumption for December 31, 2022 uses the Pri-2012 mortality table and the projected generationally scale MP-2021, adjusted to reflect the ultimate improvement rates in the 2021 Social Security Administration intermediate assumptions for plans in the United States. The mortality assumption for the Bermuda plan as of December 31, 2022 uses the 2014 Canadian Pensioners' Mortality Table combined with mortality improvement scale CPM-B.

In selecting an assumed discount rate, the Company uses a modelling process that involves selecting a portfolio of high-quality corporate debt issuances (AA- or better) whose cash flows (via coupons or maturities) match the timing and amount of the Company’s expected future benefit payments. The Company considers the results of this modelling process, as well as overall rates of return on high-quality corporate bonds and changes in such rates over time, to determine its assumed discount rate.

The rate of return assumptions are based on projected long-term market returns for the various asset classes in which the plans are invested, weighted by the target asset allocations.

Weighted average assumptions used to determine net benefit cost for 2022 and 2021 were as follows:


	Pension benefits				OPEB
	2022		2021		2022		2021
Discount rate	2.94	%	2.49	%	3.00	%	2.58	%
Expected return on assets	6.19	%	6.20	%	6.48	%	4.79	%
Rate of compensation increase	3.91	%	3.99	%	n/a		n/a
Health care cost trend rate
Before Age 65					5.88	%	5.12	%
Age 65 and after					5.88	%	5.12	%
Assumed ultimate medical inflation rate					4.75	%	4.05	%
Year in which ultimate rate is reached					2031		2031


Algonquin Power & Utilities Corp.
Notes to the Consolidated Financial Statements
December 31, 2022 and 2021
(in thousands of U.S. dollars, except as noted and per share amounts)

10.Pension and other post-employment benefits (continued)

(d)Benefit costs

The following table lists the components of net benefit cost for the pension and OPEB plans. Service cost is recorded as part of operating expenses and non-service costs are recorded as part of other net losses in the consolidated statements of operations. The employee benefit costs related to businesses acquired are recorded in the consolidated statements of operations from the date of acquisition.


	Pension benefits				OPEB
	2022		2021		2022		2021
Service cost	$	16,309	$	14,673	$	6,277	$	7,307
Non-service costs
Interest cost	24,787		20,676		9,146		8,048
Expected return on plan assets	(41,226)		(35,972)		(11,359)		(10,052)
Amortization of net actuarial loss	3,452		13,126		(56)		2,021
Amortization of prior service credits	(1,584)		(1,626)		24		11
Amortization due to plan settlements	(15)		198		—		—
Amortization of regulatory accounts	22,951		19,665		4,829		218
	$	8,365	$	16,067	$	2,584	$	246
Net benefit cost	$	24,674	$	30,740	$	8,861	$	7,553

(e)Plan assets

The Company’s investment strategy for its pension and post-employment plan assets is to maintain a diversified portfolio of assets with the primary goal of meeting long-term cash requirements as they become due.

The Company’s target asset allocation is as follows:


Asset class	Target (%)		Range (%)
Equity securities	41	%	30% -100%
Debt securities	49	%	20% - 60%
Other	10	%	0% - 20%
	100	%

The fair values of investments as of December 31, 2022, by asset category, are as follows:


Asset class	2022		Percentage
Equity securities	$	317,088	43	%
Debt securities	356,654		48	%
Other	67,680		9	%
	$	741,422	100	%

As of December 31, 2022, the plan assets do not include any material investments in AQN.


Algonquin Power & Utilities Corp.
Notes to the Consolidated Financial Statements
December 31, 2022 and 2021
(in thousands of U.S. dollars, except as noted and per share amounts)

10.Pension and other post-employment benefits (continued)

(e)Plan assets (continued)

All investments as of December 31, 2022 were valued using level 1 inputs except for 21,904 of institutional private equity investments using level 3 fair value measurement. These private equity funds invest in the private equity secondary market and in the credit markets. These funds are not traded in the open market, and are valued based on the underlying securities within the funds. The underlying securities are valued at fair value by the fund managers by using securities exchange quotations, pricing services, obtaining broker-dealer quotations, reflecting valuations provided in the most recent financial reports, or at a good faith estimate using fair market value principles.

The following table summarizes the changes fair value of these level 3 assets as of December 31:


	Level 3
Balance, January 1, 2022	$	17,314
Contributions into funds	4,781
Return on assets	2,094

Distributions	(2,285)
Balance, December 31, 2022	$	21,904

(f)Cash flows

The Company expects to contribute $22,386 to its pension plans and $9,819 to its post-employment benefit plans in 2023.

The expected benefit payments over the next ten years are as follows:


	2023		2024		2025		2026		2027		2028-2032
Pension plan	$	48,174	$	47,428	$	49,794	$	50,585	$	50,433	$	259,082
OPEB	$	11,483	$	12,025	$	12,548	$	12,925	$	13,479	$	72,684

11.Other assets

Other assets consist of the following:


	2022		2021
Restricted cash	$	43,562	$	36,232
Pension and OPEB plan assets (note 10(a))	26,482		23,630
Long-term deposits and cash collateral	22,537		14,713
Income taxes recoverable	7,100		7,649
Deferred financing costs (a)	28,586		30,544
Other (b)	21,596		10,913
	$	149,863	$	123,681
Less: current portion	(22,564)		(16,153)
	$	127,299	$	107,528

(a)Deferred financing costs

Deferred financing costs represent costs of arranging the Company’s revolving credit facilities and intercompany loans as well as the portion of transactions costs related to the Green Equity Units (note 9(c)) that will be recorded against the common shares when issued.

(b)Other

Other includes various deferred charges that are expected to be transferred to utility plant upon reaching certain milestones as well as prepaid long-term service contracts.


Algonquin Power & Utilities Corp.
Notes to the Consolidated Financial Statements
December 31, 2022 and 2021
(in thousands of U.S. dollars, except as noted and per share amounts)

12.Other long-term liabilities

Other long-term liabilities consist of the following:


	2022		2021
Contract adjustment payments (a)	$	113,876	$	187,580
Asset retirement obligations (b)	116,584		142,147
Advances in aid of construction (c)	88,546		82,584
Environmental remediation obligation (d)	42,457		55,224
Customer deposits (e)	34,675		32,629
Unamortized investment tax credits (f)	17,649		17,439
Deferred credits and contingent consideration (g)	39,498		43,495
Preferred shares, Series C (h)	12,072		13,348
Hook up fees (i)	32,463		21,904
Lease liabilities (note 1(q))	21,834		22,512
Contingent development support obligations (j)	8,824		4,615

Note payable to related party (k)	25,808		25,808
Other	41,156		34,534
	$	595,442	$	683,819
Less: current portion	(134,212)		(167,908)
	$	461,230	$	515,911

(a)Contract adjustment payment

In June 2021, the Company sold 23,000,000 Green Equity Units for total gross proceeds of $1,150,000 (note 9(c)). Total annual distributions on the Green Equity Units are at a rate of 7.75%, consisting of interest on the notes (1.18% per year) and payments under the share purchase contract (6.57% per year). The present value of the contract adjustment payments was estimated at $222,378 and recorded in other liabilities. The contract adjustment payments amount is accreted over the three-year period.

(b)Asset retirement obligations

Asset retirement obligations mainly relate to legal requirements to: (i) remove wind farm facilities upon termination of land leases; (ii) cut (disconnect from the distribution system), purge (cleanup of natural gas and polychlorinated biphenyls (“PCB”) contaminants) and cap natural gas mains within the natural gas distribution and transmission system when mains are retired in place, or sections of natural gas main are removed from the pipeline system; (iii) clean and remove storage tanks containing waste oil and other waste contaminants; (iv) remove certain river water intake structures and equipment; (v) dispose of coal combustion residuals and PCB contaminants; (vi) remove asbestos upon major renovation or demolition of structures and facilities; and (vii) decommission and restore power generation engines and related facilities.

Changes in the asset retirement obligations are as follows:


	2022		2021
Opening balance	$	142,147	$	79,968
Obligation assumed	793		57,067
Retirement activities	(27,980)		(4,133)
Accretion	4,589		4,381
Change in cash flow estimates	(2,965)		4,864
Closing balance	$	116,584	$	142,147


Algonquin Power & Utilities Corp.
Notes to the Consolidated Financial Statements
December 31, 2022 and 2021
(in thousands of U.S. dollars, except as noted and per share amounts)

12.Other long-term liabilities (continued)

(b)Asset retirement obligations (continued)

As the cost of retirement of utility assets in the United States is expected to be recovered through rates, a corresponding regulatory asset is recorded for liability accretion and asset depreciation expense (note 7(j)).

(c)Advances in aid of construction

The Company’s regulated utilities have various agreements with real estate development companies (the “developers”) conducting business within the Company’s utility service territories, whereby funds are advanced to the Company by the developers to assist with funding some or all of the costs of the development.

In many instances, developer advances can be subject to refund, but the refund is non-interest bearing. Refunds of developer advances are made over periods generally ranging from 5 to 40 years. Advances not refunded within the prescribed period are usually not required to be repaid. After the prescribed period has lapsed, any remaining unpaid balance is transferred to contributions in aid of construction and recorded as an offsetting amount to the cost of property, plant and equipment. In 2022, $1,299 (2021 - $6,376) was transferred from advances in aid of construction to contributions in aid of construction.

(d)Environmental remediation obligation

A number of the Company's regulated utilities were named as potentially responsible parties for remediation of several sites at which hazardous waste is alleged to have been disposed as a result of historical operations of manufactured natural gas plants (“MGP”) and related facilities. The Company is currently investigating and remediating, as necessary, those MGP and related sites in accordance with plans submitted to the agency with authority for each of the respective sites.

The Company estimates the remaining undiscounted, unescalated cost of the environmental cleanup activities will be $48,346 (2021 - $57,167), which at discount rates ranging from 3.4% to 4.2% represents the recorded accrual of $42,457 as of December 31, 2022 (2021 - $55,224 ). Approximately $27,410 is expected to be incurred over the next three years, with the balance of cash flows to be incurred over the following 30 years.

Changes in the environmental remediation obligation are as follows:


	2022		2021
Opening balance	$	55,224	$	69,383
Remediation activities	(5,243)		(9,865)
Accretion	2,167		1,025
Changes in cash flow estimates	1,344		2,265
Revision in assumptions	(11,035)		(7,584)


Closing balance	$	42,457	$	55,224

The Regulators for the New England Gas System and Energy North Gas System provide for the recovery of actual expenditures for site investigation and remediation over a period of 7 years and, accordingly, as of December 31, 2022, the Company has reflected a regulatory asset of $70,529 (2021 - $81,802) for the MGP and related sites (note 7(g)).

(e)Customer deposits

Customer deposits result from the Company’s obligation by Regulators to collect a deposit from customers of its facilities under certain circumstances when services are connected. The deposits are refundable as allowed under the facilities’ regulatory agreement.


Algonquin Power & Utilities Corp.
Notes to the Consolidated Financial Statements
December 31, 2022 and 2021
(in thousands of U.S. dollars, except as noted and per share amounts)

12.Other long-term liabilities (continued)

(f)Unamortized investment tax credits

The unamortized investment tax credits were assumed in connection with the acquisition of the Empire Electric System. The investment tax credits are associated with an investment made in a generating station. The credits are being amortized over the life of the generating station.

(g)Deferred credits and contingent consideration

Deferred credits and contingent consideration include unresolved contingent consideration related to prior acquisitions which is expected to be paid. In 2021, the Company recorded contingent consideration related to the acquisition of AAGES Sugar Creek Wind, LLC in an amount of $18,641 (note 3(f)).

(h)Preferred shares, Series C

AQN has 100 redeemable preferred shares, Series C issued and outstanding. The preferred shares are mandatorily redeemable in 2031 for C$53,400 per share and have a contractual cumulative cash dividend paid quarterly until the date of redemption based on a prescribed payment schedule indexed in proportion to the increase in CPI over the term of the shares. The preferred shares, Series C are convertible into common shares at the option of the holder and the Company, at any time after May 20, 2031 and before June 19, 2031, at a conversion price of C$53,400 per share.

As these shares are mandatorily redeemable for cash, they are classified as liabilities in the consolidated financial statements. The preferred shares, Series C are accounted for under the effective interest method, resulting in accretion of interest expense over the term of the shares. Dividend payments are recorded as a reduction of the preferred shares, Series C carrying value.


Estimated dividend payments due in the next five years and dividend and redemption payments thereafter are as follows:
2023	$	1,245
2024	1,443
2025	1,459
2026	1,316
2027	1,262
Thereafter to 2031	4,654
Redemption amount	3,943
	$	15,322
Less: amounts representing interest	(3,250)
	$	12,072
Less current portion	(1,245)
	$	10,827

(i)Hook up fees

Hook up fees result from the collection from customers of funds for installation and connection to the utility's infrastructure. The fees are refundable as allowed under the facilities’ regulatory agreement.

(j)Contingent development support obligations

The Company provides credit support necessary for the continued development and construction of its equity investees' wind and solar power electric development projects and infrastructure development projects. The contingent development support obligations represent the fair value of the support provided (note 8(c)).


Algonquin Power & Utilities Corp.
Notes to the Consolidated Financial Statements
December 31, 2022 and 2021
(in thousands of U.S. dollars, except as noted and per share amounts)

12.Other long-term liabilities (continued)

(k)Note payable to related party

In 2020, a subsidiary of the Company made a tax equity investment into Altavista Solar Subco, LLC, an equity investee of the Company and indirect owner of the Altavista Solar Project. Following the closing of the construction financing facility for the Altavista Solar Project, certain excess funds were distributed to the Company and in return the Company issued a promissory note payable of $30,493 to Altavista Solar Subco, LLC. The promissory note bears an interest rate of 0.675%, compounded annually. The note was repaid in full during the second quarter of 2021.

In 2021, a subsidiary of the Company made a tax equity investment into New Market Solar Investco, LLC, an equity investee of the Company and indirect owner of the New Market Solar Project (note 8(c)). Following the closing of the construction financing facility for the New Market Solar Project, certain excess funds were distributed to the Company and in return the Company issued a promissory note of $25,808 payable to New Market Solar Investco, LLC. The promissory note bears an interest rate of 4% annually and has a maturity date of December 16, 2031.

13.Shareholders’ capital

(a)Common shares

Number of common shares


	2022	2021
Common shares, beginning of year	671,960,276	597,142,219
Public offering	2,861,709	67,611,465
Dividend reinvestment plan	7,676,666	6,184,686
Exercise of share-based awards (c)	1,115,398	1,020,020
Conversion of convertible debentures	754	1,886
Common shares, end of year	683,614,803	671,960,276

Authorized

AQN is authorized to issue an unlimited number of common shares. The holders of the common shares are entitled to dividends if, as and when declared by the board of directors of AQN (the “Board”); to one vote per share at meetings of the holders of common shares; and upon liquidation, dissolution or winding up of AQN to receive pro rata the remaining property and assets of AQN, subject to the rights of any shares having priority over the common shares.

The Company has a shareholders’ rights plan (the “Rights Plan”), which expires in 2025. Under the Rights Plan, one right is issued with each issued share of the Company. The rights remain attached to the shares and are not exercisable or separable unless one or more certain specified events occur. If a person or group acting in concert acquires 20 percent or more of the outstanding shares (subject to certain exceptions) of the Company, the rights will entitle the holders thereof (other than the acquiring person or group) to purchase shares at a 50 percent discount from the then-current market price. The rights provided under the Rights Plan are not triggered by any person making a “Permitted Bid”, as defined in the Rights Plan.

(i)Public offering

On November 8, 2021, AQN issued 44,080,000 common shares at a price of $14.63 (C$18.15)per share for total gross proceeds of $642,664 (C$800,052) before issuance costs of $26,173 (C$32,583), which AQN intends to use to partially finance the Kentucky Power Transaction; provided that, in the short-term, prior to the closing of the Kentucky Power Transaction, the Company has used the net proceeds to repay certain indebtedness of AQN and its subsidiaries (note 3(b)). Forward contracts were used to manage the Canadian dollar risk (note 24(b)(iv)).


Algonquin Power & Utilities Corp.
Notes to the Consolidated Financial Statements
December 31, 2022 and 2021
(in thousands of U.S. dollars, except as noted and per share amounts)

13.Shareholders’ capital (continued)

(a) Common shares (continued)

(ii)At-the-market equity program

On August 15, 2022, AQN re-established its at-the-market equity program (“ATM program”) which allows the Company to issue up to $500,000 (or the equivalent in Canadian dollars) of common shares from treasury to the public from time to time, at the Company's discretion, at the prevailing market price when issued on the Toronto Stock Exchange (“TSX”), the New York Stock Exchange (“NYSE”), or any other existing trading market for the common shares of the Company in Canada or the United States. During the year ended December 31, 2022, the Company issued 2,861,709 common shares under the ATM program at an average price of $13.94 per common share for gross proceeds of $38,923 ($38,534 net of commissions). Other related costs were $558.

The Company has issued since the inception of the ATM program in 2019 a cumulative total of 36,814,536 common shares at an average price of $15.00 per share for gross proceeds of $551,086 ($544,295 net of commissions). Other related costs, primarily related to the establishment and subsequent re-establishments of the ATM program, were $4,843.

(iii)Dividend reinvestment plan

The Company has a common shareholder dividend reinvestment plan, which, when the plan is active, provides an opportunity for holders of AQN’s common shares who reside in Canada, the United States, or, subject to AQN’s consent, other jurisdictions, to reinvest the cash dividends paid on their common shares in additional common shares which, at AQN’s election, are either purchased on the open market or newly issued from treasury. Effective March 3, 2022, common shares purchased under the plan were issued at a 3% discount (previously at 5%) to the prevailing market price (as determined in accordance with the terms of the plan). Subsequent to year-end, AQN issued an additional 4,370,289 common shares under the dividend reinvestment plan. Effective March 16, 2023, AQN suspended the dividend reinvestment plan. Dividends will only be paid in cash while the reinvestment plan is suspended.

(b)Preferred shares

AQN is authorized to issue an unlimited number of preferred shares, issuable in one or more series, containing terms and conditions as approved by the Board.

The Company has the following preferred shares, Series A and preferred shares, Series D issued and outstanding as at December 31, 2022 and 2021:


Preferred shares	Number of shares	Price per share		Carrying amount C$		Carrying amount $
Series A	4,800,000	C$	25	C$	116,546	$	100,463
Series D	4,000,000	C$	25	C$	97,259	$	83,836
						$	184,299

The holders of preferred shares, Series A are entitled to receive quarterly fixed cumulative preferential cash dividends, if, as and when declared by the Board. The dividend for each year up to, but excluding, December 31, 2023 will be an annual amount of C$1.2905 per share. The Series A dividend rate will reset on December 31, 2023 and every five years thereafter at a rate equal to the then five-year Government of Canada bond yield plus 2.94%. The preferred shares, Series A are redeemable at C$25 per share at the option of the Company on December 31, 2023 and every fifth year thereafter. The holders of preferred shares, Series A have the right to convert their shares into cumulative floating rate preferred shares, Series B, subject to certain conditions, on December 31, 2023, and every fifth year thereafter.

The holders of preferred shares, Series D are entitled to receive fixed cumulative preferential dividends as and when declared by the Board at an annual amount of C$1.2728 per share for each year up to, but excluding, March 31, 2024. The Series D dividend will reset on March 31, 2024 and every five years thereafter at a rate equal to the then five-year Government of Canada bond plus 3.28%. The preferred shares, Series D are redeemable at C$25 per share at the option of the Company on March 31, 2024 and every fifth year thereafter. The holders of preferred shares, Series D have the right to convert their shares into cumulative floating rate preferred shares, Series E, subject to certain conditions, on March 31, 2024, and every fifth year thereafter.


Algonquin Power & Utilities Corp.
Notes to the Consolidated Financial Statements
December 31, 2022 and 2021
(in thousands of U.S. dollars, except as noted and per share amounts)

13.Shareholders’ capital (continued)

(b)Preferred shares (continued)

The Company has 100 redeemable preferred shares, Series C issued and outstanding. The mandatorily redeemable preferred shares, Series C are recorded as a liability on the consolidated balance sheets as they are mandatorily redeemable for cash (note 12(h)).

(c)Share-based compensation

For the year ended December 31, 2022, AQN recorded $10,920 (2021 - $8,395) in total share-based compensation expense as follows:


	2022		2021
Share options	$	980	$	939
Director deferred share units	960		821
Employee share purchase	562		592
Performance and restricted share units	8,418		6,043
Total share-based compensation	$	10,920	$	8,395

The compensation expense is recorded with operating expenses in the consolidated statements of operations. The portion of share-based compensation costs capitalized as cost of construction is insignificant.

As of December 31, 2022, total unrecognized compensation costs related to non-vested share-based awards was $10,732 and is expected to be recognized over a period of 1.8 years.

(i)Share option plan

The Company’s share option plan (the “Plan”) permits the grant of share options to officers, directors, employees and selected service providers. The aggregate number of shares that may be reserved for issuance under the Plan must not exceed 8% of the number of shares outstanding at the time the options are granted.

The number of shares subject to each option, the option price, the expiration date, the vesting and other terms and conditions relating to each option shall be determined by the Board (or the compensation committee of the Board (“Compensation Committee”)) from time to time. Dividends on the underlying shares do not accumulate during the vesting period. Option holders may elect to surrender any portion of the vested options that is then exercisable in exchange for the “In-the-Money Amount”. In accordance with the Plan, the “In-The-Money Amount” represents the excess, if any, of the market price of a share at such time over the option price, in each case such “In-the-Money Amount” being payable by the Company in cash or common shares at the election of the Company. As the Company does not expect to settle these instruments in cash, these options are accounted for as equity awards.

The Compensation Committee may accelerate the vesting of the unvested options then held by the optionee at the Compensation Committee's discretion. In the event that the Company restates its financial results, any unpaid or unexercised options may be cancelled at the discretion of the Compensation Committee in accordance with the terms of the Company's clawback policy.

The estimated fair value of options, including the effect of estimated forfeitures, is recognized as expense on a straight-line basis over the options’ vesting periods while ensuring that the cumulative amount of compensation cost recognized at least equals the value of the vested portion of the award at that date. The Company determines the fair value of options granted using the Black-Scholes option-pricing model. The risk-free interest rate is based on the zero-coupon Canada Government bond with a similar term to the expected life of the options at the grant date. Expected volatility was estimated based on the historical volatility of the Company’s common shares. The expected life was based on experience to date. The dividend yield rate was based upon recent historical dividends paid on AQN common shares.


Algonquin Power & Utilities Corp.
Notes to the Consolidated Financial Statements
December 31, 2022 and 2021
(in thousands of U.S. dollars, except as noted and per share amounts)

13.Shareholders’ capital (continued)

(c)Share-based compensation (continued)

(ii)Share option plan (continued)

The following assumptions were used in determining the fair value of share options granted:


	2022			2021
Risk-free interest rate	1.9		%	1.1		%
Expected volatility	23		%	23		%
Expected dividend yield	4.3		%	4.1		%
Expected life	5.50 years			5.50 years
Weighted average grant date fair value per option	C$	2.44		C$	2.46

Share option activity during the years is as follows:


	Number of awards	Weighted average exercise price		Weighted average remaining contractual term (years)	Aggregate intrinsic value
Balance, January 1, 2021	2,110,448	C$	15.45	6.55	C$	11,604
Granted	437,006	19.64		7.22	—
Exercised	(506,926)	13.92		5.95	1,453
Forfeited	—	—		—	—
Balance, December 31, 2021	2,040,528	C$	15.45	6.11	C$	3,145
Granted	646,090	19.11		7.22	—
Exercised	(40,074)	13.92		5.95	103
Forfeited	(19,764)	19.11		—	—
Balance, December 31, 2022	2,626,780	C$	16.02	5.63	C$	—
Exercisable, December 31, 2022	2,052,946	C$	17.35	5.63	C$	—

(iii)Employee share purchase plan

Under the Company’s ESPP, eligible employees may have a portion of their earnings withheld to be used to purchase the Company’s common shares. The Company will match 20% of the employee contribution amount for the first five thousand dollars per employee contributed annually and 10% of the employee contribution amount for contributions over five thousand dollars up to ten thousand dollars annually. Common shares purchased through the Company match portion shall not be eligible for sale by the participant for a period of one year following the purchase date on which such shares were acquired. At the Company’s option, the common shares may be (i) issued to participants from treasury at the average share price or (ii) acquired on behalf of participants by purchases through the facilities of the TSX or NYSE by an independent broker. The aggregate number of common shares reserved for issuance from treasury by AQN under the ESPP shall not exceed 4,000,000 common shares.


Algonquin Power & Utilities Corp.
Notes to the Consolidated Financial Statements
December 31, 2022 and 2021
(in thousands of U.S. dollars, except as noted and per share amounts)

13.Shareholders’ capital (continued)

(c)Share-based compensation (continued)

(iii)Employee share purchase plan (continued)

The Company uses the fair value based method to measure the compensation expense related to the Company’s contribution. For the year ended December 31, 2022, a total of 414,338 common shares (2021 - 355,096 ) were issued to employees under the ESPP.

(iv)Director's deferred share units

Under the Company’s DSU plan, non-employee directors of the Company may elect annually to receive all or any portion of their compensation in DSUs in lieu of cash compensation. Directors’ fees are paid on a quarterly basis and at the time of each payment of fees, the applicable amount is converted to DSUs. A DSU has a value equal to one of the Company’s common shares. Dividends accumulate in the DSU account and are converted to DSUs based on the market value of the shares on that date. DSUs cannot be redeemed until the director retires, resigns, or otherwise leaves the Board. The DSUs provide for settlement in cash or common shares at the election of the Company. As the Company does not expect to settle these instruments in cash, these options are accounted for as equity awards. For the year ended December 31, 2022, a total of 120,513 DSUs (2021 - 73,467) were issued and 5,176 DSUs (2021 - 87,582 ) were settled in exchange for 2,403 common shares issued from treasury, and 2,773 DSUs were settled at their cash value as payment for tax withholding related to the settlement of the awards. As of December 31, 2022, 645,714 (2021 - 530,378) DSUs were outstanding pursuant to the election of the directors to defer a percentage of their director’s fee in the form of DSUs. The aggregate number of common shares reserved for issuance from treasury by AQN under the DSU plan shall not exceed 1,000,000 common shares.

(v)Performance and restricted share units

The Company offers a PSU and RSU plan to its employees as part of the Company’s long-term incentive program. PSUs have been granted annually for three-year overlapping performance cycles. The PSUs vest at the end of the three-year cycle and are calculated based on established performance criteria. At the end of the three-year performance periods, the number of common shares issued can range from 2.5% to 237% of the number of PSUs granted. RSU vesting conditions and dates vary by grant and are outlined in each award letter. RSUs are not subject to performance criteria. Dividends accumulating during the vesting period are converted to PSUs and RSUs based on the market value of the shares on that date and are recorded in equity as the dividends are declared. None of the PSUs or RSUs have voting rights. Any PSUs or RSUs not vested at the end of a performance period will expire. The PSUs and RSUs provide for settlement in cash or common shares at the election of the Company. As the Company does not expect to settle these instruments in cash, these units are accounted for as equity awards. The aggregate number of common shares reserved for issuance from treasury by AQN under the PSU and RSU plan shall not exceed 7,000,000 common shares.

Compensation expense associated with PSUs is recognized rateably over the performance period. Achievement of the performance criteria is estimated at the consolidated balance sheet dates. Compensation cost recognized is adjusted to reflect the performance conditions estimated to date.


Algonquin Power & Utilities Corp.
Notes to the Consolidated Financial Statements
December 31, 2022 and 2021
(in thousands of U.S. dollars, except as noted and per share amounts)

13.Shareholders’ capital (continued)

(c)Share-based compensation (continued)

(v)Performance and restricted share units (continued)

A summary of the PSUs and RSUs follows:


	Number of awards	Weighted average grant-date fair value		Weighted average remaining contractual term (years)	Aggregate intrinsic value
Balance, January 1, 2021	2,721,207	C$	16.58	0.93	C$	54,560
Granted, including dividends	805,433	19.94		2.77	12,881
Exercised	(865,067)	13.79		—	17,005
Forfeited	(217,901)	18.64		—	3,981
Balance, December 31, 2021	2,443,672	C$	18.07	1.72	C$	44,646
Granted, including dividends	1,090,457	17.99		2.00	17,524
Exercised	(1,221,620)	12.62		—	23,636
Forfeited	(202,799)	18.94		—	418
Balance, December 31, 2022	2,109,710	C$	18.38	1.76	C$	18,608
Exercisable, December 31, 2022	769,458	C$	18.70	0.10	C$	6,787

(vi)Bonus deferral RSUs

Eligible employees have the option to receive a portion or all of their annual bonus payment in RSUs in lieu of cash. These RSUs provide for settlement in shares, and therefore these RSUs are accounted for as equity awards. The RSUs granted are 100% vested and, therefore, compensation expense associated with these RSUs is recognized immediately upon issuance.

During the year ended December, 31, 2022, 55,445 (2021 - 56,686) bonus deferral RSUs were granted to employees of the Company. In addition, the Company settled 178,368 (2021 - 152,564) bonus deferral RSUs in exchange for 82,886 (2021 - 70,571) common shares issued from treasury, and 95,482 (2021- 81,993) RSUs were settled at their cash value as payment for tax withholdings related to the settlement of the RSUs. As of December 31, 2022, 158,486 (2021 - 281,411) bonus deferral RSUs were outstanding.


Algonquin Power & Utilities Corp.
Notes to the Consolidated Financial Statements
December 31, 2022 and 2021
(in thousands of U.S. dollars, except as noted and per share amounts)

14.Accumulated other comprehensive income (loss)

AOCI consists of the following balances, net of tax:


	Foreign currency cumulative translation		Unrealized gain on cash flow hedges		Pension and post-employment actuarial changes		Total
Balance, January 1, 2021	$	(39,725)	$	50,817	$	(33,599)	$	(22,507)

Other comprehensive income (loss)	(25,982)		(97,103)		32,247		(90,838)
Amounts reclassified from AOCI to the consolidated statement of operations	(4,288)		42,772		9,804		48,288
Net current period OCI	$	(30,270)	$	(54,331)	$	42,051	$	(42,550)
OCI attributable to the non-controlling interests	(249)		—		—		(249)
Net current period OCI attributable to shareholders of AQN	$	(30,519)	$	(54,331)	$	42,051	$	(42,799)
Amount reclassified from AOCI to non-controlling interest	(6,371)		—		—		(6,371)
Balance, December 31, 2021	$	(76,615)	$	(3,514)	$	8,452	$	(71,677)
Other comprehensive income (loss)	(18,013)		(128,838)		23,722		(123,129)
Amounts reclassified from AOCI to the consolidated statement of operations	(5,489)		34,543		4,039		33,093
Net current period OCI	$	(23,502)	(94,295)		27,761		$	(90,036)
OCI attributable to the non-controlling interests	1,650		—		—		1,650
Net current period OCI attributable to shareholders of AQN	$	(21,852)	(94,295)		27,761		$	(88,386)

Balance, December 31, 2022	$	(98,467)	$	(97,809)	$	36,213	$	(160,063)

Amounts reclassified from AOCI for foreign currency cumulative translation affected interest expense and derivative gain (loss); those for unrealized gain (loss) on cash flow hedges affected revenue from non-regulated energy sales, interest expense and derivative gain (loss) while those for pension and post-employment actuarial changes affected pension and post-employment non-service costs.

15.Dividends

All dividends of the Company are made on a discretionary basis as determined by the Board. The Company declares and pays the dividends on its common shares in U.S. dollars. Dividends declared were as follows:


	2022				2021
	Dividend		Dividend per share		Dividend		Dividend per share
Common shares	$	486,043	$	0.7130	$	423,023	$	0.6669
Preferred shares, Series A	C$	6,194	C$	1.2905	C$	6,194	C$	1.2905
Preferred shares, Series D	C$	5,091	C$	1.2728	C$	5,091	C$	1.2728


Algonquin Power & Utilities Corp.
Notes to the Consolidated Financial Statements
December 31, 2022 and 2021
(in thousands of U.S. dollars, except as noted and per share amounts)

16.Related party transactions

(a)Equity-method investments

The Company provides administrative and development services to its equity-method investees and is reimbursed for incurred costs. To that effect, during 2022, the Company charged its equity-method investees $63,861 (2021 - $25,778). Additionally, Liberty Development JV Inc., an equity-method investee (note 8(c)) provides development services to the Company on specified projects, for which it earns a development fee upon reaching certain milestones. During the year, the development fees charged to the Company were $12,628 (2021 - $2,036).

Investment and acquisition transactions with equity-method investments are described in note 8(c). In addition, during 2021, the Company paid $1,500 to Abengoa S.A. (“Abengoa”) to purchase all of Abengoa's interests in the AAGES, AAGES Development Canada Inc., and AAGES Development Spain, S.A. joint ventures. The assets acquired for AAGES Development Spain S.A. included project development assets for $2,662 and working capital of $1,507. The loan at that date between the Company and AAGES Development Spain S.A. of $3,089 was treated as additional consideration paid to acquire the partnership.

In 2020, the Company issued a promissory note of $30,493 payable to Altavista Solar Subco, LLC, an equity investee of the Company at the time. The note was repaid in full during the second quarter of 2021. During the fourth quarter of 2021, the Company issued a promissory note of $25,808 payable to New Market Solar Investco, LLC, an equity investee of the Company (note 12(k)).

(b)Non-controlling interest and redeemable non-controlling interest held by related party

Non-controlling interest and redeemable non-controlling interest held by related party are described in note 17.

During 2021, the Company sold Colombian solar assets to Atlantica for consideration of $23,863, with a gain on sale of $878, and contingent consideration of $2,600. The contingency was resolved in 2022 and, as a result, an additional gain of $1,200 was recognized.

The above related party transactions have been recorded at the exchange amounts agreed to by the parties to the transactions.

17.Non-controlling interests and redeemable non-controlling interests

Net effect attributable to non-controlling interests for the years ended December 31 consists of the following:


	2022		2021

HLBV and other adjustments attributable to:
Non-controlling interests - tax equity partnership units	$	108,695	$	88,417
Non-controlling interests - redeemable tax equity partnership units	6,298		6,902
Other net earnings attributable to:
Non-controlling interests	(3,670)		(5,682)
	$	111,323	$	89,637
Redeemable non-controlling interest, held by related party	(15,157)		(10,435)
Net effect of non-controlling interests	$	96,166	$	79,202

The non-controlling tax equity investors (“tax equity partnership units”) in the Company's U.S. wind power and solar power generating facilities are entitled to allocations of earnings, tax attributes and cash flows in accordance with contractual agreements. The share of earnings attributable to the non-controlling interest holders in these subsidiaries is calculated using the HLBV method of accounting as described in note 1(s).


Algonquin Power & Utilities Corp.
Notes to the Consolidated Financial Statements
December 31, 2022 and 2021
(in thousands of U.S. dollars, except as noted and per share amounts)

17.Non-controlling interests and redeemable non-controlling interests (continued)

Non-controlling interests


	Non-controlling interests - tax equity partnership units (a)				Other non-controlling interests (b)				Non-controlling interests held by related parties (c)
	2022		2021		2022		2021		2022		2021
Opening balance	$	1,377,117	$	388,253	$	64,807	$	11,234	$	81,158	$	59,125
Net earnings attributable to NCI	(105,371)		(87,422)		345		3,354		—		—
Contributions received, net	6,182		1,058,929		267,515		51,451		—		39,376
Dividends and distributions declared	(40,086)		(11,795)		—		(1,021)		(20,978)		(17,793)
Repurchase of non-controlling interest	(12,249)		—		—		—		—		—
Non-controlling interest assumed on asset acquisition	—		29,141		—		—		—		—
OCI	15		11		695		(211)		(2,358)		450

Closing balance	$	1,225,608	$	1,377,117	$	333,362	$	64,807	$	57,822	$	81,158

(a) Non-controlling interests - tax equity partnership units

The Company obtained control of the three Mid-West Wind Facilities, Sugar Creek Wind Facility and Maverick Creek Wind Facility in 2021 (notes 3(d) and 3(f)), assuming non-controlling interest of $29,141. Post acquisition in 2021, third-party tax equity investors funded $530,880, $380,829 and $147,914, to the Mid-West Wind Facilities, the Sugar Creek Wind Facility and the Maverick Creek Wind Facility, respectively, in exchange for Class A partnership units in the entities.

(b) Other non-controlling interests

On December 29, 2022, the Company sold a 49% non-controlling interest in three operating wind facilities in the United States totalling 551 MW of installed capacity: the Odell Wind Facility in Minnesota, the Deerfield Wind Facility in Michigan and the Sugar Creek Wind Facility in Illinois. The consideration of $277,500 was recorded as an increase to non-controlling interest, except for a portion of $5,000, which is subject to refund if some conditions are met and as such was recorded as redeemable non-controlling interest.

In January 2021, the Company sold a 32% interest in Eco Acquisitionco SpA, the holding company through which AQN's interest in ESSAL is held, to a third party for consideration of $51,750. This represents an interest of 30% in the aggregate interest in ESSAL, which was reflected by a corresponding increase in non-controlling interest. This transaction resulted in no gain or loss. Following this transaction, AQN indirectly owns approximately 64% of the outstanding shares of ESSAL and continues to consolidate ESSAL's operations.

In November 2021, Liberty Development JV Inc. invested $39,376 in Algonquin (AY Holdco) B.V., a consolidated subsidiary of the Company. In May 2019, AYES Canada acquired an interest in a consolidated subsidiary of the Company for $96,752 (C$130,103) (note 8(b)). The investment by AYES Canada and Liberty Development JV Inc. are presented as a non-controlling interest held by related parties.


Algonquin Power & Utilities Corp.
Notes to the Consolidated Financial Statements
December 31, 2022 and 2021
(in thousands of U.S. dollars, except as noted and per share amounts)

17.Non-controlling interests and redeemable non-controlling interests (continued)

Redeemable non-controlling interests

Non-controlling interests in subsidiaries that are redeemable upon the occurrence of uncertain events not solely within AQN’s control are classified as temporary equity on the consolidated balance sheets. If the redemption is probable or currently redeemable, the Company records the instruments at their redemption value. Redemption is not considered probable as of December 31, 2022.

Liberty Global Energy Solutions (note 8(c)), an equity investee of the Company, has a secured credit facility in the amount of $306,500 maturing on January 26, 2024. It is collateralized through a pledge of Atlantica ordinary shares held by AY Holdings. A collateral shortfall would occur if the net obligation (as defined in the credit agreement) would equal or exceed 50% of the market value of such Atlantica shares, in which case the lenders would have the right to sell Atlantica shares to eliminate the collateral shortfall. The Liberty Global Energy Solutions secured credit facility is repayable on demand if Atlantica ceases to be a public company or if certain other events are announced or completed that could restrict AY Holdings’ ability to sell or transfer its Atlantica ordinary shares. Liberty Global Energy Solutions has a preference share ownership in AY Holdings which AQN reflects as redeemable non-controlling interest held by related party.

Changes in redeemable non-controlling interests are as follows:


	Redeemable non-controlling interests held by related party				Redeemable non-controlling interests
	2022		2021		2022		2021
Opening balance	$	306,537	$	306,316	$	12,989	$	20,859
Net earnings attributable to NCI	15,157		10,435		(6,298)		(6,902)
Contributions, net of costs	—		—		5,000		—
Dividends and distributions declared	(13,838)		(10,214)		(171)		(968)

Closing balance	$	307,856	$	306,537	$	11,520	$	12,989

18.Income taxes

The provision for income taxes in the consolidated statements of operations represents an effective tax rate different than the Canadian enacted statutory rate of 26.5% (2021 - 26.5%). The differences are as follows:


	2022		2021
Expected income tax expense at Canadian statutory rate	$	(97,962)	$	37,691
Increase (decrease) resulting from:
Effect of differences in tax rates on transactions in and within foreign jurisdictions and change in tax rates	(55,315)		(47,600)
Adjustments from investments carried at fair value	51,314		2,709
Non-controlling interests share of income	30,025		25,135
Change in valuation allowance	41,702		(118)
Non-deductible acquisition costs	1,341		3,733
Acquisition related state deferred tax adjustments	5,998		—
Capital gain rate differential on disposal of renewable assets	(7,340)		—
Tax credits	(18,440)		(49,415)
Adjustment relating to prior periods	(1,390)		1,333
Deferred income taxes on regulated income recorded as regulatory assets	(2,155)		(3,807)
Amortization and settlement of excess deferred income tax	(14,855)		(16,778)
Other	5,564		3,692
Income tax recovery	$	(61,513)	$	(43,425)


Algonquin Power & Utilities Corp.
Notes to the Consolidated Financial Statements
December 31, 2022 and 2021
(in thousands of U.S. dollars, except as noted and per share amounts)

18.Income taxes (continued)

For the years ended December 31, 2022 and 2021, earnings (loss) before income taxes consist of the following:


	2022		2021
Canada (1)	$	(363,050)	$	(60,848)
U.S.	(37,322)		153,719
Other regions	30,704		49,361
	$	(369,668)	$	142,232

(1) Inclusive of fair value gain (loss) on investments carried at fair value (note 8)

Income tax expense (recovery) attributable to income (loss) consists of:


	Current		Deferred		Total
Year ended December 31, 2022
Canada	$	4,184	$	(74,595)	$	(70,411)
United States	1,579		6,183		7,762
Other regions	2,080		(944)		1,136
	$	7,843	$	(69,356)	$	(61,513)
Year ended December 31, 2021
Canada	$	4,560	$	(33,993)	$	(29,433)
United States	1,024		(19,772)		(18,748)
Other regions	1,653		3,103		4,756
	$	7,237	$	(50,662)	$	(43,425)


Algonquin Power & Utilities Corp.
Notes to the Consolidated Financial Statements
December 31, 2022 and 2021
(in thousands of U.S. dollars, except as noted and per share amounts)

18.Income taxes (continued)

The tax effect of temporary differences between the financial statement carrying amounts of assets and liabilities and their respective tax bases that give rise to significant portions of the deferred tax assets and deferred tax liabilities as of December 31, 2022 and 2021 are presented below:


	2022		2021
Deferred tax assets:
Non-capital loss, investment tax credits, currently non-deductible interest expenses, and financing costs	$	878,000	$	761,666
Pension and OPEB	16,845		46,580
Environmental obligation	12,118		15,271
Regulatory liabilities	156,285		166,939
Other	61,917		64,460
Total deferred income tax assets	$	1,125,165	$	1,054,916
Less: valuation allowance	(107,583)		(27,471)
Total deferred tax assets	$	1,017,582	$	1,027,445
Deferred tax liabilities:
Property, plant and equipment	$	846,331	$	782,829
Outside basis differentials	315,581		412,665
Regulatory accounts	303,059		300,072
Other	33,834		30,471
Total deferred tax liabilities	$	1,498,805	$	1,526,037
Net deferred tax liabilities	$	(481,223)	$	(498,592)
Consolidated balance sheets classification:
Deferred tax assets	$	84,416	$	31,595
Deferred tax liabilities	(565,639)		(530,187)
Net deferred tax liabilities	$	(481,223)	$	(498,592)

The valuation allowance for deferred tax assets as of December 31, 2022 was $107,583 (2021 - $27,471). The valuation allowance primarily relates to operating losses that, in the judgment of management, are not more likely than not to be realized. In assessing the realizability of deferred tax assets, management considers whether it is more likely than not that some portion or all of the deferred tax assets will not be realized. The ultimate realization of deferred tax assets is dependent upon the generation of future taxable income during the periods in which those temporary differences become deductible. Management considers the scheduled reversal of deferred tax liabilities (including the impact of available carryback and carryforward periods), projected future taxable income, and tax-planning strategies in making this assessment. The amount of the deferred tax asset considered realizable, however, could be adjusted if estimates of future taxable income during the carryforward period are reduced or increased or if objective negative evidence in the form of cumulative losses is no longer present and additional weight is given to subjective evidence such as Management projections for growth.

Primarily as a result of the impairment charges discussed in notes 5 and 8(c), the U.S. entities in the Renewable Energy Group, which have historically been in an overall deferred tax liability position, are in an overall deferred tax asset position as at December 31, 2022. In the course of assessing the U.S. deferred tax assets in the Renewable Energy Group, management concluded that, during the fourth quarter of 2022, it was no longer probable that the Renewable Energy Group would generate sufficient taxable income to realize the benefit of the deferred tax assets of such group. AQN’s conclusion is based on the balance of all available positive and negative evidence applicable to the Renewable Energy Group, including material impairment charges recorded on certain assets, insufficient taxable temporary differences to allow the full utilization of the deferred tax asset, insufficient forecasted taxable income and a historical 3 year cumulative loss position.


Algonquin Power & Utilities Corp.
Notes to the Consolidated Financial Statements
December 31, 2022 and 2021
(in thousands of U.S. dollars, except as noted and per share amounts)

18.Income taxes (continued)

The following table illustrates the annual movement in the deferred tax valuation allowance:


	2022		2021
Beginning balance	$	27,471	$	29,824
Charged to income tax expense (recovery)	41,702		(118)
Charged (reduction) to OCI	40,613		(1,707)
Reductions to other accounts	(2,203)		(528)
Ending balance	$	107,583	$	27,471

As of December 31, 2022, the Company had non-capital losses carried forward and tax credits available to reduce future years' taxable income, which expire as follows:


Non-capital loss carryforward and credits	2023—2027		2028+		Total
Canada	$	3,261	$	728,529	$	731,790
US	9,962		1,707,139		1,717,101
Total non-capital loss carryforward	$	13,223	$	2,435,668	$	2,448,891
Tax credits	$	4,428	$	151,676	$	156,104

The Company has provided for deferred income taxes for the estimated tax cost of distributed earnings of certain of its subsidiaries. Deferred income taxes have not been provided on approximately $824,052 of undistributed earnings of certain foreign subsidiaries, as the Company has concluded that such earnings are indefinitely reinvested and should not give rise to additional tax liabilities. A determination of the amount of the unrecognized tax liability relating to the remittance of such undistributed earnings is not practicable.

19.Other net losses

Other net losses consist of the following:


	2022		2021

Acquisition and transition-related costs	$	17,442	$	14,507


Other (a)	3,949		8,442
	$	21,391	$	22,949

(a)Other

Other losses primarily consist of costs pertaining to a condemnation proceeding, and miscellaneous asset write-downs, net of miscellaneous gains. Other losses in 2021 also included an adjustment to a regulatory liability pertaining to the true-up of prior period tracking accounts.


Algonquin Power & Utilities Corp.
Notes to the Consolidated Financial Statements
December 31, 2022 and 2021
(in thousands of U.S. dollars, except as noted and per share amounts)

20.Basic and diluted net earnings (loss) per share

Basic and diluted earnings per share have been calculated on the basis of net earnings attributable to the common shareholders of the Company and the weighted average number of common shares and bonus deferral restricted share units outstanding. Diluted net earnings per share is computed using the weighted-average number of common shares, additional shares issued subsequent to year-end under the dividend reinvestment plan, PSUs, RSUs and DSUs outstanding during the year and, if dilutive, potential incremental common shares related to the convertible debentures or resulting from the application of the treasury stock method to outstanding share options and Green Equity Units (note 9(c)).

The reconciliation of the net earnings and the weighted average shares used in the computation of basic and diluted earnings per share are as follows:


	2022		2021
Net earnings (loss) attributable to shareholders of AQN	$	(211,989)	$	264,859
Preferred shares, Series A dividend	4,786		4,942
Preferred shares, Series D dividend	3,934		4,061


Net earnings (loss) attributable to common shareholders of AQN – basic and diluted	$	(220,709)	$	255,856
Weighted average number of shares
Basic	677,862,207		622,347,677
Effect of dilutive securities	—		6,600,185
Diluted	677,862,207		628,947,862

This calculation of diluted shares excludes the potential impact of the Green Equity Units and all potential incremental shares that may become issuable pursuant to outstanding securities of the Company for the year ended December 31, 2022, as they are antidilutive. The common shares potentially issuable for the year ended December 31, 2021, as a result of 437,006 share options are excluded from this calculation as they are anti-dilutive.


Algonquin Power & Utilities Corp.
Notes to the Consolidated Financial Statements
December 31, 2022 and 2021
(in thousands of U.S. dollars, except as noted and per share amounts)

21.Segmented information

The Company is managed under two primary business units consisting of the Regulated Services Group and the Renewable Energy Group. The two business units are the two segments of the Company.

The Regulated Services Group, the Company's regulated operating unit, owns and operates a portfolio of electric, water distribution and wastewater collection, and natural gas utility systems and transmission operations in the United States, Canada, Bermuda and Chile; the Renewable Energy Group, the Company's non-regulated operating unit, owns and operates, or has investments in, a diversified portfolio of renewable and thermal energy generation assets.

For purposes of evaluating the performance of the business units, the Company allocates the realized portion of any gains or losses on financial instruments to the specific business units. Dividend income from Atlantica and AYES Canada are included in the operations of the Renewable Energy Group, while interest income from SAWS is included in the operations of the Regulated Services Group. Equity method gains and losses are included in the operations of the Regulated Services Group or Renewable Energy Group based on the nature of the activities of the investees. The change in value of investments carried at fair value and unrealized portion of any gains or losses on derivative instruments not designated in a hedging relationship are not considered in management’s evaluation of divisional performance and are therefore allocated and reported under corporate.


	Year ended December 31, 2022
	Regulated Services Group		Renewable Energy Group		Corporate		Total
Revenue (1)(2)	$	2,328,536	$	350,939	$	—	$	2,679,475
Other revenue	55,732		28,447		1,501		85,680
Fuel, power and water purchased	824,670		41,826		—		866,496
Net revenue	1,559,598		337,560		1,501		1,898,659
Operating expenses	736,515		114,463		511		851,489
Administrative expenses	46,484		26,424		7,324		80,232
Depreciation and amortization	317,300		137,203		1,017		455,520
Asset impairment expense	—		159,568		—		159,568
Loss on foreign exchange	—		—		13,833		13,833
	459,299		(100,098)		(21,184)		338,017
Gain on sale of renewable assets	—		64,028		—		64,028
Operating income (loss)	459,299		(36,070)		(21,184)		402,045
Interest expense	(113,482)		(64,285)		(100,807)		(278,574)


Income (loss) from long-term investments	21,884		15,254		(502,344)		(465,206)
Other	(14,765)		(570)		(12,598)		(27,933)
Earnings (loss) before income taxes	$	352,936	$	(85,671)	$	(636,933)	$	(369,668)
Property, plant and equipment	$	8,554,938	$	3,360,687	$	29,260	$	11,944,885
Investments carried at fair value	1,984		1,342,223		—		1,344,207
Equity-method investees	56,199		310,103		15,500		381,802
Total assets	12,109,575		5,251,933		266,105		17,627,613
Capital expenditures	$	908,676	$	180,348	$	—	$	1,089,024

(1) Renewable Energy Group revenue includes $63,717 related to net hedging loss from energy derivative contracts and availability credits for the year ended December 31, 2022 that do not represent revenue recognized from contracts with customers.

(2) Regulated Services Group revenue includes $21,640 related to alternative revenue programs for the year ended December 31, 2022 that do not represent revenue recognized from contracts with customers.


Algonquin Power & Utilities Corp.
Notes to the Consolidated Financial Statements
December 31, 2022 and 2021
(in thousands of U.S. dollars, except as noted and per share amounts)

21.Segmented information (continued)


	Year ended December 31, 2021
	Regulated Services Group		Renewable Energy Group		Corporate		Total
Revenue (1)(2)	$	1,944,171	$	256,633	$	—	$	2,200,804
Other revenue	53,441		18,339		1,558		73,338
Fuel and power purchased	682,602		31,313		—		713,915
Net revenue	1,315,010		243,659		1,558		1,560,227
Operating expenses	597,850		104,262		16		702,128
Administrative expenses	37,179		28,298		1,249		66,726
Depreciation and amortization	280,452		121,414		1,097		402,963
Loss on foreign exchange	—		—		4,371		4,371
	399,529		(10,315)		(5,175)		384,039
Gain on sale of renewable assets	—		29,063		—		29,063
Operating income (loss)	399,529		18,748		(5,175)		413,102
Interest expense	(93,411)		(71,598)		(44,545)		(209,554)


Income (loss) from long-term investments	18,306		84,046		(128,809)		(26,457)
Other	(24,177)		(2,956)		(7,726)		(34,859)
Earnings (loss) before income taxes	$	300,247	$	28,240	$	(186,255)	$	142,232
Property, plant and equipment	$	7,394,151	$	3,615,915	$	32,380	$	11,042,446
Investments carried at fair value	2,296		1,846,160		—		1,848,456
Equity-method investees	37,492		375,460		20,898		433,850
Total assets	10,524,466		6,123,888		149,149		16,797,503
Capital expenditures	$	998,855	$	338,637	$	7,553	$	1,345,045

(1) Renewable Energy Group revenue includes $57,018 related to net hedging loss from energy derivative contracts for the year ended December 31, 2021 that do not represent revenue recognized from contracts with customers.

(2) Regulated Services Group revenue includes $19,043 related to alternative revenue programs for the year ended December 31, 2021 that do not represent revenue recognized from contracts with customers.

The majority of non-regulated energy sales are earned from contracts with large public utilities. The Company has sought to mitigate its credit risk by selling energy to large utilities in various North American locations. None of the utilities contribute more than 10% of total revenue.


Algonquin Power & Utilities Corp.
Notes to the Consolidated Financial Statements
December 31, 2022 and 2021
(in thousands of U.S. dollars, except as noted and per share amounts)

21.Segmented information (continued)

AQN operates in the independent power and utility industries in the United States, Canada and other regions. Information on operations by geographic area is as follows:


	2022		2021
Revenue
United States	$	2,232,959	$	1,790,539
Canada	175,005		157,854
Other regions	357,191		325,749
	$	2,765,155	$	2,274,142
Property, plant and equipment
United States	$	10,351,736	$	9,464,716
Canada	848,560		882,454
Other regions	744,589		695,276
	$	11,944,885	$	11,042,446
Intangible assets
United States	$	18,818	$	23,575
Canada	19,038		21,780
Other regions	58,827		59,761
	$	96,683	$	105,116

Revenue is attributed to the regions based on the location of the underlying generating and utility facilities.


Algonquin Power & Utilities Corp.
Notes to the Consolidated Financial Statements
December 31, 2022 and 2021
(in thousands of U.S. dollars, except as noted and per share amounts)

22.Commitments and contingencies

(a)Contingencies

AQN and its subsidiaries are involved in various claims and litigation arising out of the ordinary course and conduct of its business. Although such matters cannot be predicted with certainty, management does not consider AQN’s exposure to such litigation to be material to these consolidated financial statements. Accruals for any contingencies related to these items are recorded in the consolidated financial statements at the time it is concluded that its occurrence is probable and the related liability is estimable.

Condemnation expropriation proceedings

On January 7, 2016, the Town of Apple Valley filed a lawsuit seeking to condemn the utility assets of Liberty Utilities (Apple Valley Ranchos Water) Corp. (“Liberty Apple Valley”). On May 7, 2021, the Court issued a Tentative Statement of Decision denying the Town of Apple Valley’s attempt to take the Apple Valley Water System by eminent domain. The ruling confirmed that Liberty Apple Valley’s continued ownership and operation of the water system is in the best interest of the community. On October 14, 2021, the Court issued the Final Statement of Decision. The Court signed and entered an Order of Dismissal and Judgment on November 12, 2021. On January 7, 2022, the Town filed a notice of appeal of the judgment entered by the Court. On August 2, 2022, the Court issued a ruling awarding Liberty Apple Valley approximately $13,222 in attorney’s fees and litigation costs. The Town filed a notice of appeal of the fee award on August 22, 2022. The Town’s appeal of the condemnation judgment and fee award have been consolidated into one appellate docket. The Company has not recorded the possible recovery of these attorney’s fees and litigation costs.

Mountain View fire

On November 17, 2020, a wildfire now known as the Mountain View Fire occurred in the territory of Liberty Utilities (CalPeco Electric) LLC ("Liberty CalPeco"). The cause of the fire remains under investigation, and CAL FIRE has not yet released its final report. There are currently 17 active lawsuits that name certain subsidiaries of the Company as defendants in connection with the Mountain View Fire, as well as one non-litigation claim brought by the U.S. Department of Agriculture seeking reimbursement for alleged fire suppression costs. Twelve lawsuits are brought by groups of individual plaintiffs alleging causes of action including negligence, inverse condemnation, nuisance, trespass, and violations of Cal. Pub. Util. Code 2106 and Cal. Health and Safety Code 13007 (one of these twelve lawsuits also alleges the wrongful death of an individual and various subrogation claims on behalf of insurance companies). In another lawsuit, County of Mono, Antelope Valley Fire Protection District, Toiyabe Indian Health Project, and Bridgeport Indian Colony allege similar causes of action and seek damages for fire suppression costs, law enforcement costs, property and infrastructure damage, and other costs. In four other lawsuits, insurance companies allege inverse condemnation and negligence and seek recovery of amounts paid and to be paid to their insureds. The likelihood of success in these lawsuits cannot be reasonably predicted. Liberty CalPeco intends to vigorously defend them. The Company has wildfire liability insurance that is expected to apply up to applicable policy limits.

(b)Commitments

In addition to the commitments related to the proposed acquisitions and development projects disclosed in notes 3(b) and 8, the following significant commitments exist as of December 31, 2022.

AQN has outstanding purchase commitments for power purchases, natural gas supply and service agreements, service agreements, capital project commitments and land easements.


Algonquin Power & Utilities Corp.
Notes to the Consolidated Financial Statements
December 31, 2022 and 2021
(in thousands of U.S. dollars, except as noted and per share amounts)

22.Commitments and contingencies (continued)

(b)Commitments (continued)

Detailed below are estimates of future commitments under these arrangements:


	Year 1		Year 2		Year 3		Year 4		Year 5		Thereafter		Total
Power purchase (i)	$	89,846	$	32,490	$	32,726	$	12,274	$	12,520	$	142,586	$	322,442
Natural gas supply and service agreements (ii)	113,775		81,719		57,014		40,372		31,457		188,138		512,475
Service agreements	67,477		57,886		55,835		49,596		46,511		298,516		575,821
Capital projects	7,163		—		—		—		—		—		7,163
Land easements	13,295		13,316		13,503		13,667		13,837		463,785		531,403
Total	$	291,556	$	185,411	$	159,078	$	115,909	$	104,325	$	1,093,025	$	1,949,304

(i) Power purchase: AQN’s electric distribution facilities have commitments to purchase physical quantities of power for load serving requirements. The commitment amounts included in the table above are based on market prices as of December 31, 2022. However, the effects of purchased power unit cost adjustments are mitigated through a purchased power rate-adjustment mechanism.

(ii) Natural gas supply and service agreements: AQN’s natural gas distribution facilities and thermal generation facilities have commitments to purchase physical quantities of natural gas under contracts for purposes of load serving requirements and of generating power.

23.Non-cash operating items

The changes in non-cash operating items consist of the following:


	2022		2021
Accounts receivable	$	(124,631)	$	(56,751)

Fuel and natural gas in storage	(21,140)		(43,642)
Supplies and consumables inventory	(24,088)		445
Income taxes recoverable	549		(3,025)
Prepaid expenses	(4,269)		(1,189)
Accounts payable	24,395		(33,399)
Accrued liabilities	127,076		31,845
Current income tax liability	(2,741)		4,363
Asset retirements and environmental obligations	(22,342)		(1,185)
Net regulatory assets and liabilities	(174,427)		(419,484)
	$	(221,618)	$	(522,022)


Algonquin Power & Utilities Corp.
Notes to the Consolidated Financial Statements
December 31, 2022 and 2021
(in thousands of U.S. dollars, except as noted and per share amounts)

24.Financial instruments

(a)Fair value of financial instruments


December 31, 2022	Carrying amount		Fair value		Level 1		Level 2		Level 3
Long-term investments carried at fair value	$	1,344,207	$	1,344,207	$	1,270,138	$	—	$	74,083
Development loans and other receivables	53,680		50,300		—		50,300		—
Derivative instruments:

Energy contracts not designated as cash flow hedge	393		393		—		—		393

Interest rate swap designated as a hedge	69,188		69,188		—		69,188		—

Interest rate cap not designated as a hedge	2,659		2,659		—		2,659		—
Congestion revenue rights not designated as a cash flow hedge	10,110		10,110		—		—		10,110

Cross currency swap designated as a net investment hedge	1,267		1,267		—		1,267		—

Commodity contracts for regulated operations	283		283		—		283		—
Total derivative instruments	83,900		83,900		—		73,397		10,503
Total financial assets	$	1,481,787	$	1,478,407	$	1,270,138	$	123,697	$	84,586
Long-term debt	$	7,512,017	$	6,699,031	$	2,623,628	$	4,075,403	$	—
Notes payable to related party	25,808		15,180		—		15,180		—
Convertible debentures	245		276		276		—		—
Preferred shares, Series C	12,072		11,675		—		11,675		—
Derivative instruments:
Energy contracts designated as a cash flow hedge	120,284		120,284		—		—		120,284
Energy contracts not designated as a cash flow hedge	8,617		8,617		—		—		8,617


Cross-currency swap designated as a net investment hedge	24,371		24,371		—		24,371		—


Cross currency swap designated as a cash flow hedge	15,435		15,435		—		15,435		—
Commodity contracts for regulated operations	1,614		1,614		—		1,614		—
Total derivative instruments	170,321		170,321		—		41,420		128,901
Total financial liabilities	$	7,720,463	$	6,896,483	$	2,623,904	$	4,143,678	$	128,901


Algonquin Power & Utilities Corp.
Notes to the Consolidated Financial Statements
December 31, 2022 and 2021
(in thousands of U.S. dollars, except as noted and per share amounts)

24.Financial instruments (continued)

(a)Fair value of financial instruments (continued)


December 31, 2021	Carrying amount		Fair value		Level 1		Level 2		Level 3
Long-term investment carried at fair value	$	1,848,456	$	1,848,456	$	1,753,210	$	—	$	95,246
Development loans and other receivables	32,261		33,286		—		33,286		—
Derivative instruments:
Energy contracts designated as a cash flow hedge	15,362		15,362		—		—		15,362
Interest rate swap designated as a hedge	1,581		1,581		—		1,581		—

Cross-currency swap designated as a net investment hedge	1,958		1,958		—		1,958		—

Commodity contracts for regulated operations	1,721		1,721		—		1,721		—

Total derivative instruments	20,622		20,622		—		5,260		15,362
Total financial assets	$	1,901,339	$	1,902,364	$	1,753,210	$	38,546	$	110,608
Long-term debt	$	6,211,375	$	6,543,933	$	2,418,580	$	4,125,352	$	—
Notes payable to related party	25,808		25,808		—		25,808		—
Convertible debentures	277		519		519		—		—
Preferred shares, Series C	13,348		14,580		—		14,580		—
Derivative instruments:
Energy contracts designated as a cash flow hedge	60,462		60,462		—		—		60,462
Energy contracts not designated as a cash flow hedge	1,169		1,169		—		—		1,169
Cross-currency swap designated as a net investment hedge	50,258		50,258		—		50,258		—
Interest rate swaps designated as a hedge	7,008		7,008		—		7,008		—

Commodity contracts for regulated operations	1,348		1,348		—		1,348		—
Total derivative instruments	120,245		120,245		—		58,614		61,631
Total financial liabilities	$	6,371,053	$	6,705,085	$	2,419,099	$	4,224,354	$	61,631

The Company has determined that the carrying value of its short-term financial assets and liabilities approximates fair value as of December 31, 2022 and 2021 due to the short-term maturity of these instruments.


Algonquin Power & Utilities Corp.
Notes to the Consolidated Financial Statements
December 31, 2022 and 2021
(in thousands of U.S. dollars, except as noted and per share amounts)

24.Financial instruments (continued)

(a)Fair value of financial instruments (continued)

The fair value of the investment in Atlantica (level 1) is measured at the closing price on the NASDAQ stock exchange.

The fair value of development loans and other receivables (level 2) is determined using a discounted cash flow method, using estimated current market rates for similar instruments adjusted for estimated credit risk as determined by management.

The Company’s level 1 fair value of long-term debt is measured at the closing price on the NYSE and the Canadian over-the-counter closing price. The Company’s level 2 fair value of long-term debt at fixed interest rates, notes payable to related party and preferred shares Series C has been determined using a discounted cash flow method and current interest rates. The Company's level 2 fair value of convertible debentures has been determined as the greater of their face value and the quoted value of AQN's common shares on a converted basis.

The Company’s level 2 fair value derivative instruments primarily consist of swaps, options, rights, caps, subscription agreements and forward physical derivatives where market data for pricing inputs are observable. Level 2 pricing inputs are obtained from various market indices and utilize discounting based on quoted interest rate curves, which are observable in the marketplace.

The Company’s level 3 instruments consist of energy contracts for electricity sales, congestion revenue rights ("CRRs") and the fair value of the Company's investment in AYES Canada. The significant unobservable inputs used in the fair value measurement of energy contracts are the internally developed forward market prices ranging from $23.32 to $109.91 with a weighted average of $44.76 as of December 31, 2022. The weighted average forward market prices are developed based on the quantity of energy expected to be sold monthly and the expected forward price during that month. The change in the fair value of the energy contracts is detailed in notes 24(b)(ii) and 24(b)(iv). The significant unobservable inputs used in the fair value measurement of CRRs are recent CRR auction prices ranging from $nil to $23.20 with a weighted average of $7.83 as at December 31, 2022. The fair value of the investment in AYES Canada is determined using a discounted cash flow approach combined with a binomial tree approach. The significant unobservable inputs used in the fair value measurement of the Company's AYES Canada investment are the expected cash flows, the discount rates applied to these cash flows ranging from 8.00% to 8.50% with a weighted average of 8.34%, and the expected volatility of Atlantica's share price ranging from 26.99% to 34.89% as of December 31, 2022. Significant increases (decreases) in expected cash flows or increases (decreases) in discount rate in isolation would have resulted in a significantly lower (higher) fair value measurement.

(b)Derivative instruments

Derivative instruments are recognized on the consolidated balance sheets as either assets or liabilities and measured at fair value at each reporting period.

(i)Commodity derivatives – regulated accounting

The Company uses derivative financial instruments to reduce the cash flow variability associated with the purchase price for a portion of future natural gas purchases associated with its regulated natural gas and electric service territories. The Company’s strategy is to minimize fluctuations in natural gas sale prices to regulated customers.

The following are commodity volumes, in dekatherms (“dths”), associated with the above derivative contracts:


			2022
Financial contracts: Swaps			1,687,217
Options			35,824

			1,723,041


Algonquin Power & Utilities Corp.
Notes to the Consolidated Financial Statements
December 31, 2022 and 2021
(in thousands of U.S. dollars, except as noted and per share amounts)

24.Financial instruments (continued)

(b)Derivative instruments (continued)

(i)Commodity derivatives – regulated accounting (continued)

The accounting for these derivative instruments is subject to guidance for rate regulated enterprises. Therefore, the fair value of these derivatives is recorded as current or long-term assets and liabilities, with offsetting positions recorded as regulatory assets and regulatory liabilities in the consolidated balance sheets. Most of the gains or losses on the settlement of these contracts are included in the calculation of the fuel and commodity costs adjustments (note 7(a)). As a result, the changes in fair value of these natural gas derivative contracts and their offsetting adjustment to regulatory assets and liabilities had no earnings impact.

(ii)Cash flow hedges

The Company reduces the price risk on the expected future sale of power generation by entering into the following long-term energy derivative contracts. Upon the acquisition of the Sugar Creek Wind Facility in 2021 (note 3(f)), the Company redesignated a long-term energy derivative contract to mitigate the price risk on the expected future sale of power generation. The fair value of the derivative on the redesignation date will be amortized into earnings over the remaining life of the contract.


Notional quantity (MW-hrs)	Expiry	Receive average prices (per MW-hr)	Pay floating price (per MW-hr)
4,059,905	September 2030	$24.54	Illinois Hub
413,620	December 2028	$29.15	PJM Western HUB
1,977,766	December 2027	$22.05	NI HUB
1,665,318	December 2027	$36.46	ERCORT North HUB

The Company is party to two interest rate swap contracts as cash flow hedges to mitigate the risk that interest rates will increase over the life of certain term loan facilities. Under the terms of the interest rate swap contracts, the Company has fixed its interest rate expense on such term loan facilities. The fair value of the derivative on the designation date is amortized into earnings over the remaining life of the contract.

The Company is party to a forward-starting interest rate swap in order to reduce the interest rate risk related to the quarterly interest payments between July 1, 2024 and July 1, 2029 on the $350,000 subordinated unsecured notes. The Company designated the entire notional amount of the pay-variable and receive-fixed interest rate swaps as a hedge of the future quarterly variable-rate interest payments associated with the subordinated unsecured notes.

In January 2022, the Company entered into a cross-currency interest rate swap, coterminous with the Canadian Notes, to effectively convert the C$400,000 Canadian Offering into U.S. dollars. The change in the carrying amount of the Canadian Notes due to changes in spot exchange rates is recognized each period in the consolidated statements of operations as loss (gain) on foreign exchange. The Company designated the entire notional amount of the cross-currency fixed-for-fixed interest rate swap as a hedge of the foreign currency exposure related to cash flows for the interest and principal repayments on the Canadian Notes. An offsetting portion of the AOCI balance related to changes in fair value of the cross-currency fixed-for-fixed interest rate swap attributable to changes in the spot exchange rates is also immediately reclassified into the consolidated statements of operations as an offsetting (gain) loss on foreign exchange.


Algonquin Power & Utilities Corp.
Notes to the Consolidated Financial Statements
December 31, 2022 and 2021
(in thousands of U.S. dollars, except as noted and per share amounts)

24.Financial instruments (continued)

(b)Derivative instruments (continued)

(ii)Cash flow hedges (continued)

The following table summarizes OCI attributable to derivative financial instruments designated as a cash flow hedge:


	2022		2021
Effective portion of cash flow hedge	$	(128,838)	$	(97,103)
Amortization of cash flow hedge	(12,180)		(2,132)
Amounts reclassified from AOCI	46,723		44,904


OCI attributable to shareholders of AQN	$	(94,295)	$	(54,331)

The Company expects $32,467 of unrealized losses currently in AOCI to be reclassified, net of taxes into non-regulated energy sales, investment loss, interest expense and derivative gains, respectively, within the next 12 months, as the underlying hedged transactions settle.

(iii)Foreign exchange hedge of net investment in foreign operation

The functional currency of most of AQN's operations is the U.S. dollar. The Company designates obligations denominated in Canadian dollars as a hedge of the foreign currency exposure of its net investment in its Canadian investments and subsidiaries. The related foreign currency transaction gain or loss designated as, and effective as, a hedge of the net investment in a foreign operation is reported in the same manner as the translation adjustment (in OCI) related to the net investment. A foreign currency gain of $2,262 for the year ended December 31, 2022 (2021 - loss of $168) was recorded in OCI.

On May 23, 2019, the Company entered into a cross-currency swap, coterminous with the subordinated unsecured notes issued on such date, to effectively convert the $350,000 U.S. dollar denominated offering into Canadian dollars. The change in the carrying amount of the notes due to changes in spot exchange rates is recognized each period in the consolidated statements of operations as loss (gain) on foreign exchange. The Company designated the entire notional amount of the cross-currency fixed-for-fixed interest rate swap as a hedge of the foreign currency exposure related to cash flows for the interest and principal repayments on the notes. Upon the change in functional currency of AQN to the U.S. dollar on January 1, 2020, this hedge was dedesignated. The OCI related to this hedge will be amortized into earnings in the period that future interest payments affect earnings over the remaining life of the original hedge. The Company redesignated this swap as a hedge of AQN's net investment in its Canadian subsidiaries.

The related foreign currency transaction gain or loss designated as a hedge of the net investment in a foreign operation is reported in the same manner as the translation adjustment (in OCI) related to the net investment. The fair value of the derivative on the redesignation date will be amortized over the remaining life of the original hedge. A foreign currency gain of $22,091 for the year ended December 31, 2022 (2021 - loss of $4,232 was recorded in OCI).

Canadian operations

The Company is exposed to currency fluctuations from its Canadian-based operations. AQN manages this risk primarily through the use of natural hedges by using Canadian long-term debt to finance its Canadian operations and a combination of foreign exchange forward contracts and spot purchases.

The Company’s Canadian operations are determined to have the Canadian dollar as their functional currency and are exposed to currency fluctuations from their U.S. dollar transactions. The Company designates obligations denominated in U.S. dollars as a hedge of the foreign currency exposure of its net investment in its U.S. investments and subsidiaries. The related foreign currency transaction gain or loss designated as, and effective as, a hedge of the net investment in a foreign operation is reported in the same manner as the translation adjustment (in OCI) related to the net investment. A foreign currency loss of $18,561 for the year ended December 31, 2022 (2021 - gain of $1,595) was recorded in OCI.


Algonquin Power & Utilities Corp.
Notes to the Consolidated Financial Statements
December 31, 2022 and 2021
(in thousands of U.S. dollars, except as noted and per share amounts)

24.Financial instruments (continued)

(b)Derivative instruments (continued)

(iii)Foreign exchange hedge of net investment in foreign operation (continued)

Canadian operations (continued)

The Company is party to C$300,000 (December 31, 2021 - $500,000) fixed-for-fixed cross-currency cross currency swaps to effectively convert Canadian dollar debentures into U.S. dollars. In February 2022, the Company settled the cross-currency swap related to its C$200,000 (2021 - C$150,000) debenture that was repaid. The Company designated the entire notional amount of the cross-currency fixed-for-fixed interest rate swap and related short-term U.S. dollar payables created by the monthly accruals of the swap settlement as a hedge of the foreign currency exposure of its net investment in the Renewable Energy Group's U.S. operations. The gain or loss related to the fair value changes of the swap and the related foreign currency gains and losses on the U.S. dollar accruals that are designated as, and are effective as, a hedge of the net investment in a foreign operation are reported in the same manner as the translation adjustment (in OCI) related to the net investment. A loss of $11,082 for the year ended December 31, 2022 (2021 - gain of $7,824) was recorded in OCI.

On April 9, 2021, the Renewable Energy Group entered into a fixed-for-fixed cross-currency interest rate swap, coterminous with the senior unsecured debentures issued on such date (note 9(g)), to effectively convert the C$400,000 Canadian-dollar-denominated offering into U.S. dollars. The Renewable Energy Group designated the entire notional amount of the fixed-for-fixed cross-currency interest rate swap and related short-term U.S. dollar payables created by the monthly accruals of the swap settlement as a hedge of the foreign currency exposure of its net investment in the Renewable Energy Group's U.S. operations. The gain or loss related to the fair value changes of the swap and the related foreign currency gains and losses on the U.S. dollar accruals that are designated as, and are effective as, a hedge of the net investment in a foreign operation are reported in the same manner as the translation adjustment (in OCI) related to the net investment. A loss of $13,374 for the year ended December 31, 2022 (2021 - loss of $1,925) was recorded in OCI.

Chilean operations

The Company is exposed to currency fluctuations from its Chilean-based operations. The Company's Chilean operations are determined to have the Chilean peso as their functional currency. Chilean long-term debt used to finance the operations is denominated in Chilean Unidad de Fomento.

(iv)Other derivatives and risk management

In the normal course of business, the Company is exposed to financial risks that potentially impact its operating results. The Company employs risk management strategies with a view to mitigating these risks to the extent possible on a cost-effective basis. Derivative financial instruments are used to manage certain exposures to fluctuations in exchange rates, interest rates and commodity prices. The Company does not enter into derivative financial agreements for speculative purposes. For derivatives that are not designated as hedges, the changes in the fair value are immediately recognized in earnings.

The Company mitigates the volatility of energy congestion charges at the ERCOT transmission grid by entering into CRRs, which as of December 31, 2022 had notional quantity of 1,328,510 MW-hours at prices ranging from $1.58 per MW-hr to $19.06 per MW-hr with a weighted average of $7.80 per MW-hr for January 2023 to April 2025. These CRRs are not designated as an accounting hedge.

On December 17, 2022, the Company entered into an interest rate cap agreement in the amount of $390,000 for the period between January 15, 2023 and January 15, 2024. The Company was party to an interest rate swap to mitigate the interest rate risk related to debt at its Blue Hill Wind Facility. The contract was novated upon the sale of the Blue Hill Wind Facility. The loss recognized on the derivative was recorded as a reduction of the gain on sale of renewable assets on the consolidated statements of operations (note 3(a)).


Algonquin Power & Utilities Corp.
Notes to the Consolidated Financial Statements
December 31, 2022 and 2021
(in thousands of U.S. dollars, except as noted and per share amounts)

24.Financial instruments (continued)

(b)Derivative instruments (continued)

(iv)Other derivatives and risk management (continued)

The Company mitigates the price risk on the expected future sale of power generation of one of its solar facilities through a long-term energy derivative contract with a notional quantity of 516,202 MW-hours, a price of $25.15 per MW-hr and expiring in August 2030 as an economic hedge to the price of energy sales. The derivative contract is not designated as an accounting hedge.

During 2021, the Company executed on currency forward contracts to manage the currency exposure to the Canadian dollar shares issuance (note 13(a)). A foreign currency gain of $2,329 was recorded in 2021 as a result of the settlement.

The effects on the consolidated statements of operations of derivative financial instruments not designated as hedges consist of the following:


	2022		2021
Unrealized gain (loss) on derivative financial instruments:


Energy derivative contracts	$	(945)	$	(5,353)

Commodity contracts	185		—
Total unrealized loss on derivative financial instruments	$	(760)	$	(5,353)
Realized gain (loss) on derivative financial instruments:
Energy derivative contracts	$	6,939	$	(108)
Currency forward contract	—		2,329
Interest rate swaps	(7,185)		—
Total realized gain (loss) on derivative financial instruments	$	(246)	$	2,221
Loss on derivative financial instruments not accounted for as hedges	(1,006)		(3,132)
Amortization of AOCI gains frozen as a result of hedge dedesignation	3,465		3,712
	$	2,459	$	580
Consolidated statements of operations classification:
Gain on derivative financial instruments	$	4,408	$	4,403
Gain on foreign exchange	—		2,329
Renewable energy sales	5,236		(6,152)
Reduction to gain on sale of renewable assets	(7,185)		—
	$	2,459	$	580


Algonquin Power & Utilities Corp.
Notes to the Consolidated Financial Statements
December 31, 2022 and 2021
(in thousands of U.S. dollars, except as noted and per share amounts)

24.Financial instruments (continued)

(c)Risk management (continued)

In addition to the risk management strategies described above, the Company manages exposure to risks arising from financial instruments, including credit risk and liquidity risk.

Credit risk

Credit risk is the risk of an unexpected loss if a customer or counterparty to a financial instrument fails to meet its contractual obligations. The Company’s financial instruments that are exposed to concentrations of credit risk are primarily cash and cash equivalents, accounts receivable, notes receivable and derivative instruments. The Company limits its exposure to credit risk with respect to cash equivalents by ensuring available cash is deposited with its senior lenders, all of which have a credit rating of A or better. The Company does not consider the risk associated with the accounts receivable to be significant as the majority of revenue from power generation is earned from large utility customers having a credit rating of Baa2 or better by Moody's, or BBB or higher by S&P, or BBB or higher by DBRS. Revenue is generally invoiced and collected within 45 days.

The remaining revenue is primarily earned by the Regulated Services Group, which consists of electric, water distribution and wastewater, and natural gas utilities in the United States, Canada, Bermuda and Chile. In this regard, the credit risk related to Regulated Services Group accounts receivable balances of $404,258 is spread over hundreds of thousands of customers. The Company has processes in place to monitor and evaluate this risk on an ongoing basis including background credit checks and security deposits from new customers. In addition, most of the Regulators of the Regulated Services Group allow for a reasonable bad debt expense to be incorporated in the rates and therefore recovered from rate payers.

As of December 31, 2022, the Company’s maximum exposure to credit risk for these financial instruments was as follows:



	2022
Cash and cash equivalents and restricted cash	$	101,185
Accounts receivable	552,914
Allowance for doubtful accounts	(24,857)
Notes receivable	53,680
	$	682,922

In addition, the Company monitors the creditworthiness of the counterparties to its foreign exchange, interest rate, and energy derivative contracts and assesses each counterparty’s ability to perform on the transactions set forth in the contracts. The counterparties consist primarily of financial institutions. This concentration of counterparties may impact the Company’s overall exposure to credit risk, either positively or negatively, in that the counterparties may be similarly affected by changes in economic, regulatory or other conditions.

Liquidity risk

Liquidity risk is the risk that the Company will not be able to meet its financial obligations as they fall due. The Company’s approach to managing liquidity risk is to take steps to ensure, to the extent possible, that it will have sufficient liquidity to meet liabilities when due. As of December 31, 2022, in addition to cash on hand of $57,623, the Company had $2,288,765 available to be drawn on its revolving and term credit facilities. Each of the Company’s revolving credit facilities contain covenants that may limit amounts available to be drawn.


Algonquin Power & Utilities Corp.
Notes to the Consolidated Financial Statements
December 31, 2022 and 2021
(in thousands of U.S. dollars, except as noted and per share amounts)

24.Financial instruments (continued)

(c)Risk management (continued)

Liquidity risk (continued)

The Company’s liabilities mature as follows:


	Due less than 1 year		Due 2 to 3 years		Due 4 to 5 years		Due after 5 years		Total
Long-term debt obligations	$	1,128,660	$	404,633	$	1,984,855	$	4,019,166	$	7,537,314

Interest on long-term debt	310,863		447,227		386,560		3,936,205		5,080,855
Purchase obligations	741,888		—		—		—		741,888
Environmental obligation	9,326		18,084		1,915		19,021		48,346
Advances in aid of construction	1,554		—		—		86,992		88,546
Derivative financial instruments:
Cross-currency swap	3,205		5,541		6,279		24,781		39,806


Energy derivative and commodity contracts	29,286		49,865		29,896		21,468		130,515

Contract adjustment payments on Green Equity Units	76,208		37,668		—		—		113,876
Other obligations	37,209		6,392		5,080		271,962		320,643
Total obligations	$	2,338,199	$	969,410	$	2,414,585	$	8,379,595	$	14,101,789

25.Comparative figures

Certain of the comparative figures have been reclassified to conform to the consolidated financial statement presentation adopted in the current year.

NOTICE TO READER

Algonquin Power & Utilities Corp. (the “Corporation”) has refiled this Management Discussion and Analysis (“MD&A”) to update the date of the MD&A to March 17, 2023, being a date that is not prior to the date of the auditor’s report on the Corporation’s annual consolidated financial statements for the year ended December 31, 2022. No other changes were made to the MD&A from the version filed on SEDAR on March 17, 2023.

Management Discussion & Analysis

Management of Algonquin Power & Utilities Corp. (“AQN” or the “Company” or the “Corporation”) has prepared the following discussion and analysis to provide information to assist its shareholders’ understanding of the financial results for the three and twelve months ended December 31, 2022. This Management Discussion & Analysis (“MD&A”) should be read in conjunction with AQN’s annual consolidated financial statements for the years ended December 31, 2022 and 2021. This material is available on SEDAR at www.sedar.com, on EDGAR at www.sec.gov/edgar, and on the AQN website at www.AlgonquinPowerandUtilities.com. Additional information about AQN, including the most recent Annual Information Form (“AIF”), can be found on SEDAR at www.sedar.com and on EDGAR at www.sec.gov/edgar.

Unless otherwise indicated, financial information provided for the years ended December 31, 2022 and 2021 has been prepared in accordance with generally accepted accounting principles in the United States (“U.S. GAAP”). As a result, the Company's financial information may not be comparable with financial information of other Canadian companies that provide financial information on another basis.

All monetary amounts are in U.S. dollars, except where otherwise noted. We denote any amounts denominated in Canadian dollars with "C$" immediately prior to the stated amount.

Capitalized terms used herein and not otherwise defined have the meanings assigned to them in the Company's most recent AIF.

Unless noted otherwise, this MD&A is based on information available to management as of March 17, 2023.

Contents


Caution Concerning Forward-Looking Statements and Forward-Looking Information			2
Caution Concerning Non-GAAP Measures			4
Overview and Business Strategy			6
Significant Updates			9
Outlook			10
2022 Fourth Quarter Results From Operations			12
2022 Annual Results from Operations			14
2022 Net Earnings Summary			16
2022 Adjusted EBITDA Summary			17
Regulated Services Group			18
Renewable Energy Group			28
AQN: Corporate and Other Expenses			34
Non-GAAP Financial Measures			36

Summary of Property, Plant and Equipment Expenditures			39
Liquidity and Capital Reserves			41
Share-Based Compensation Plans			44
Management of Capital Structure			45
Related Party Transactions			46
Enterprise Risk Management			47
Quarterly Financial Information			64
Summary Financial Information of Atlantica			65
Disclosure Controls and Procedures			65

Critical Accounting Estimates and Policies			66



Algonquin Power & Utilities Corp. - Management Discussion & Analysis			1

Caution Concerning Forward-Looking Statements and Forward-Looking Information

This document may contain statements that constitute "forward-looking information" within the meaning of applicable securities laws in each of the provinces and territories of Canada and the respective policies, regulations and rules under such laws or "forward-looking statements" within the meaning of the U.S. Private Securities Litigation Reform Act of 1995 (collectively, “forward-looking information”). The words "aims", “anticipates”, “believes”, “budget”, “could”, “estimates”, “expects”, “forecasts”, “intends”, “may”, “might”, “plans”, “projects”, “schedule”, “should”, “will”, “would”, "seeks", "strives", "targets" (and grammatical variations of such terms) and similar expressions are often intended to identify forward-looking information, although not all forward-looking information contains these identifying words. Specific forward-looking information in this document includes, but is not limited to, statements relating to: expected future growth, earnings (including 2023 Adjusted Net Earnings per common share) and results of operations; liquidity, capital resources and operational requirements; sources of funding, including adequacy and availability of credit facilities, cash flows from operations, capital markets financing, and asset recycling initiatives (including the 2023 Asset Recycling Plan (as defined herein)); expectations regarding the use of proceeds from financings; ongoing and planned acquisitions, dispositions, projects, initiatives or other transactions, including expectations regarding timing, costs, financing, results, ownership structures, regulatory matters, in-service dates and completion dates; financing plans, including the Company's expectation that it will not undertake any new common equity financing through the end of 2024; expectations regarding future macroeconomic conditions; expectations regarding the anticipated closing of the Kentucky Power Transaction (as defined herein); expectations regarding the purchase price for the Kentucky Power Transaction; expectations regarding the financial impacts of the flooding that occurred in Kentucky Power’s service territory in late July 2022; expectations regarding financing of the Kentucky Power Transaction; expectations regarding the Company's corporate development activities and the results thereof, including the expected business mix between the Regulated Services Group and Renewable Energy Group; expectations regarding regulatory hearings, motions, filings, appeals and approvals, including rate reviews, and the timing, impacts and outcomes thereof; expected future generation, capacity and production of the Company’s energy facilities; expectations regarding future capital investments, including expected timing, investment plans, sources of funds and impacts; joint ventures; expectations regarding the outcome of legal claims and disputes; strategy and goals; dividends to shareholders, including expectations regarding the sustainability thereof and the Company's ability to achieve its targeted annual dividend payout ratio; expectations regarding future "greening the fleet" initiatives, including with respect to Kentucky Power; credit ratings and equity credit from rating agencies; expectations regarding debt repayment and refinancing; the future impact on the Company of actual or proposed laws, regulations and rules; the expected impact of changes in customer usage on the Regulated Services Group’s revenue; accounting estimates; interest rates, including the anticipated effect of an increase thereof; the implementation of new technology systems and infrastructure, including the expected timing thereof; financing costs; and currency exchange rates. All forward-looking information is given pursuant to the “safe harbour” provisions of applicable securities legislation.

The forecasts and projections that make up the forward-looking information contained herein are based on certain factors or assumptions which include, but are not limited to: the receipt of applicable regulatory approvals and requested rate decisions; the absence of a material increase in the costs of compliance with environmental laws following the completion of the Kentucky Power Transaction; the absence of material adverse regulatory decisions being received and the expectation of regulatory stability; the absence of any material equipment breakdown or failure; availability of financing (including tax equity financing and self-monetization transactions for U.S. federal tax credits) on commercially reasonable terms and the stability of credit ratings of the Corporation and its subsidiaries; the absence of unexpected material liabilities or uninsured losses; the continued availability of commodity supplies and stability of commodity prices; the absence of interest rate increases or significant currency exchange rate fluctuations; the absence of significant operational, financial or supply chain disruptions or liability, including relating to import controls and tariffs; the continued ability to maintain systems and facilities to ensure their continued performance; the absence of a severe and prolonged downturn in general economic, credit, social or market conditions; the successful and timely development and construction of new projects; the closing of pending acquisitions substantially in accordance with the expected timing for such acquisitions; the absence of capital project or financing cost overruns; sufficient liquidity and capital resources; the continuation of long term weather patterns and trends; the absence of significant counterparty defaults; the continued competitiveness of electricity pricing when compared with alternative sources of energy; the realization of the anticipated benefits of the Corporation’s acquisitions and joint ventures; the absence of a change in applicable laws, political conditions, public policies and directions by governments, materially negatively affecting the Corporation; the ability to obtain and maintain licenses and permits; maintenance of adequate insurance coverage; the absence of material fluctuations in market energy prices; the absence of material disputes with taxation authorities or changes to applicable tax laws; continued maintenance of information technology infrastructure and the absence of a material breach of cybersecurity; the successful implementation of new information technology systems and infrastructure; favourable relations with external stakeholders; favourable labour relations; the realization of the anticipated benefits of the Kentucky Power Transaction, including that it will be accretive to the Corporation’s Adjusted Net Earnings per common share; that the Corporation will be able to successfully integrate newly acquired entities, and the absence of any material adverse changes to such entities prior to closing; the successful transfer of operational control over the Mitchell Plant (as defined herein) to Wheeling Power



Algonquin Power & Utilities Corp. - Management Discussion & Analysis			2

Company; the Mitchell Plant being transferred or retired in accordance with the Corporation’s expectations; the absence of undisclosed liabilities of entities being acquired; that such entities will maintain constructive regulatory relationships with state regulatory authorities; the ability of the Corporation to retain key personnel of acquired entities and the value of such employees; no adverse developments in the business and affairs of the sellers during the period when transitional services are provided to the Corporation in connection with any acquisition; the ability of the Corporation to satisfy its liabilities and meet its debt service obligations following completion of any acquisition; the absence of any reputational harm to the Corporation as a result of any acquisition; and the ability of the Corporation to successfully execute future “greening the fleet” initiatives.

The forward-looking information contained herein is subject to risks, uncertainties and other factors that could cause actual results to differ materially from historical results or results anticipated by the forward-looking information. Factors which could cause results or events to differ materially from current expectations include, but are not limited to: changes in general economic, credit, social or market conditions; changes in customer energy usage patterns and energy demand; reductions in the liquidity of energy markets; global climate change; the incurrence of environmental liabilities; natural disasters, diseases, pandemics, public health emergencies and other force majeure events; critical equipment breakdown or failure; supply chain disruptions; the imposition of import controls or tariffs; the failure of information technology infrastructure and other cybersecurity measures to protect against data, privacy and cybersecurity breaches; failure to successfully implement, and cost overruns and delays in connection with, new information technology systems and infrastructure; physical security breach; the loss of key personnel and/or labour disruptions; seasonal fluctuations and variability in weather conditions and natural resource availability; reductions in demand for electricity, natural gas and water due to developments in technology; reliance on transmission systems owned and operated by third parties; issues arising with respect to land use rights and access to the Corporation’s facilities; terrorist attacks; fluctuations in commodity and energy prices; capital expenditures; reliance on subsidiaries; the incurrence of an uninsured loss; a credit rating downgrade; an increase in financing costs or limits on access to credit and capital markets; significant inflation; increases and fluctuations in interest rates and failure to manage exposure to credit and financial instrument risk; currency exchange rate fluctuations; restricted financial flexibility due to covenants in existing credit agreements; an inability to refinance maturing debt on favourable terms; disputes with taxation authorities or changes to applicable tax laws; failure to identify, acquire, develop or timely place in service projects to maximize the value of tax credits; requirement for greater than expected contributions to post-employment benefit plans; default by a counterparty; inaccurate assumptions, judgments and/or estimates with respect to asset retirement obligations; failure to maintain required regulatory authorizations; changes in, or failure to comply with, applicable laws and regulations; failure of compliance programs; failure to identify attractive acquisition or development candidates necessary to pursue the Corporation’s growth strategy; failure to dispose of assets (at all or at a competitive price) to fund the Company’s operations and growth plans; delays and cost overruns in the design and construction of projects, including as a result of COVID-19; loss of key customers; failure to complete or realize the anticipated benefits of acquisitions or joint ventures; Atlantica (as defined herein) or a third party joint venture partner acting in a manner contrary to the Corporation’s interests; a drop in the market value of Atlantica's ordinary shares; facilities being condemned or otherwise taken by governmental entities; increased external stakeholder activism adverse to the Corporation’s interests; fluctuations in the price and liquidity of the Corporation’s common shares and the Corporation's other securities; the severity and duration of the COVID-19 pandemic, including the potential resurgence of COVID-19 and/or new strains of COVID-19, and collateral consequences thereof, including the disruption of economic activity, volatility in capital and credit markets and legislative and regulatory responses; impact of significant demands placed on the Corporation as a result of pending acquisitions or growth strategies; potential undisclosed liabilities of any entities being acquired by the Corporation; uncertainty regarding the length of time required to complete pending acquisitions; the failure to implement the Corporation’s strategic objectives or achieve expected benefits relating to acquisitions; Kentucky Power’s failure to receive regulatory approval for the construction of new renewable generation facilities; indebtedness of any entity being acquired by the Corporation; reputational harm and increased costs of compliance with environmental laws as a result of announced or completed acquisitions; unanticipated expenses and/or cash payments as a result of change of control and/or termination for convenience provisions in agreements to which any entity being acquired is a party; and the reliance on third parties for certain transitional services following the completion of an acquisition. Although the Corporation has attempted to identify important factors that could cause actual actions, events or results to differ materially from those described in forward-looking information, there may be other factors that cause actions, events or results not to be as anticipated, estimated or intended. Some of these and other factors are discussed in more detail under the heading Enterprise Risk Management in this MD&A and under the heading Enterprise Risk Factors in the Corporation's most recent AIF.

Forward-looking information contained herein (including any financial outlook) is provided for the purposes of assisting the reader in understanding the Corporation and its business, operations, risks, financial performance, financial position and cash flows as at and for the periods indicated and to present information about management’s current expectations and plans relating to the future, and the reader is cautioned that such information may not be appropriate for other purposes. Forward-looking information contained herein is made as of the date of this document and based on the plans, beliefs, estimates, projections, expectations, opinions and assumptions of management on the date hereof. There can be no



Algonquin Power & Utilities Corp. - Management Discussion & Analysis

assurance that forward-looking information will prove to be accurate, as actual results and future events could differ materially from those anticipated in such forward-looking information. Accordingly, readers should not place undue reliance on forward-looking information. While subsequent events and developments may cause the Corporation’s views to change, the Corporation disclaims any obligation to update any forward-looking information or to explain any material difference between subsequent actual events and such forward-looking information, except to the extent required by applicable law. All forward-looking information contained herein is qualified by these cautionary statements.

Caution Concerning Non-GAAP Measures

AQN uses a number of financial measures to assess the performance of its business lines. Some measures are calculated in accordance with U.S. GAAP, while other measures do not have a standardized meaning under U.S. GAAP. These non-GAAP measures include non-GAAP financial measures and non-GAAP ratios, each as defined in Canadian National Instrument 52-112 Non-GAAP and Other Financial Measures Disclosure. AQN’s method of calculating these measures may differ from methods used by other companies and therefore may not be comparable to similar measures presented by other companies.

The terms “Adjusted Net Earnings”, “Adjusted Earnings Before Interest, Taxes, Depreciation and Amortization” (“Adjusted EBITDA”), “Adjusted Funds from Operations”, "Net Energy Sales", "Net Utility Sales" and "Divisional Operating Profit", which are used throughout this MD&A, are non-GAAP financial measures. An explanation of each of these non-GAAP financial measures is set out below and a reconciliation to the most directly comparable U.S. GAAP measure, in each case, can be found in this MD&A. In addition, “Adjusted Net Earnings” is presented throughout this MD&A on a per common share basis. Adjusted Net Earnings per common share is a non-GAAP ratio and is calculated by dividing Adjusted Net Earnings by the weighted average number of common shares outstanding during the applicable period.

AQN does not provide reconciliations for forward-looking non-GAAP financial measures as AQN is unable to provide a meaningful or accurate calculation or estimation of reconciling items and the information is not available without unreasonable effort. This is due to the inherent difficulty of forecasting the timing or amount of various events that have not yet occurred, are out of AQN’s control and/or cannot be reasonably predicted, and that would impact the most directly comparable forward-looking U.S. GAAP financial measure. For these same reasons, AQN is unable to address the probable significance of the unavailable information. Forward-looking non-GAAP financial measures may vary materially from the corresponding U.S. GAAP financial measures.

Adjusted EBITDA

Adjusted EBITDA is a non-GAAP financial measure used by many investors to compare companies on the basis of ability to generate cash from operations. AQN uses these calculations to monitor the amount of cash generated by AQN. AQN uses Adjusted EBITDA to assess the operating performance of AQN without the effects of (as applicable): depreciation and amortization expense, income tax expense or recoveries, acquisition and transition costs, certain litigation expenses, interest expense, gain or loss on derivative financial instruments, write down of intangibles and property, plant and equipment, earnings attributable to non-controlling interests, non-service pension and post-employment costs, cost related to tax equity financing, costs related to management succession and executive retirement, costs related to prior period adjustments due to changes in tax law, costs related to condemnation proceedings, financial impacts on the Company's Senate Wind Facility from the significantly elevated pricing that persisted in the Electric Reliability Council of Texas ("ERCOT") market over several days (the "Market Disruption Event") as a result of the February 2021 extreme winter storm conditions experienced in Texas and parts of the central U.S. (the “Midwest Extreme Weather Event”), gain or loss on foreign exchange, earnings or loss from discontinued operations, changes in value of investments carried at fair value, and other typically non-recurring or unusual items. AQN adjusts for these factors as they may be non-cash, unusual in nature and are not factors used by management for evaluating the operating performance of the Company. AQN believes that presentation of this measure will enhance an investor’s understanding of AQN’s operating performance. Adjusted EBITDA is not intended to be representative of cash provided by operating activities or results of operations determined in accordance with U.S. GAAP, and can be impacted positively or negatively by these items. For a reconciliation of Adjusted EBITDA to net earnings, see Non-GAAP Financial Measures starting on page 36 of this MD&A.

Adjusted Net Earnings

Adjusted Net Earnings is a non-GAAP financial measure used by many investors to compare net earnings from operations without the effects of certain volatile primarily non-cash items that generally have no current economic impact or items such as acquisition expenses or certain litigation expenses that are viewed as not directly related to a company’s operating performance. AQN uses Adjusted Net Earnings to assess its performance without the effects of (as applicable): gains or losses on foreign exchange, foreign exchange forward contracts, interest rate swaps, acquisition and transition costs, one-time costs of arranging tax equity financing, certain litigation expenses and write down of intangibles and property, plant and equipment, earnings or loss from discontinued operations (excluding sale of assets in the course of normal operations), unrealized mark-to-market revaluation impacts (other than those realized in connection with the sales of development assets), costs related to management succession and executive retirement, costs related to prior period adjustments due to changes in tax law, costs related to condemnation proceedings, financial impacts from the Market Disruption Event on the



Algonquin Power & Utilities Corp. - Management Discussion & Analysis

Company's Senate Wind Facility, changes in value of investments carried at fair value, and other typically non-recurring or unusual items as these are not reflective of the performance of the underlying business of AQN. AQN believes that analysis and presentation of net earnings or loss on this basis will enhance an investor’s understanding of the operating performance of its businesses. Adjusted Net Earnings is not intended to be representative of net earnings or loss determined in accordance with U.S. GAAP, and can be impacted positively or negatively by these items. For a reconciliation of Adjusted Net Earnings to net earnings, see Non-GAAP Financial Measures starting on page 37 of this MD&A.

Adjusted Funds from Operations

Adjusted Funds from Operations is a non-GAAP financial measure used by investors to compare cash provided by operating activities without the effects of certain volatile items that generally have no current economic impact or items such as acquisition expenses that are viewed as not directly related to a company’s operating performance. AQN uses Adjusted Funds from Operations to assess its performance without the effects of (as applicable): changes in working capital balances, acquisition and transition costs, certain litigation expenses, cash provided by or used in discontinued operations, financial impacts from the Market Disruption Event on the Company's Senate Wind Facility, and other typically non-recurring items affecting cash from operations as these are not reflective of the long-term performance of the underlying businesses of AQN. AQN believes that analysis and presentation of funds from operations on this basis will enhance an investor’s understanding of the operating performance of its businesses. Adjusted Funds from Operations is not intended to be representative of cash provided by operating activities as determined in accordance with U.S. GAAP, and can be impacted positively or negatively by these items. For a reconciliation of Adjusted Funds from Operations to cash provided by operating activities, see Non-GAAP Financial Measures starting on page 38 of this MD&A.

Net Energy Sales

Net Energy Sales is a non-GAAP financial measure used by investors to identify revenue after commodity costs used to generate revenue where such revenue generally increases or decreases in response to increases or decreases in the cost of the commodity used to produce that revenue. AQN uses Net Energy Sales to assess its revenues without the effects of fluctuating commodity costs as such costs are predominantly passed through either directly or indirectly in the rates that are charged to customers. AQN believes that analysis and presentation of Net Energy Sales on this basis will enhance an investor’s understanding of the revenue generation of the Renewable Energy Group. It is not intended to be representative of revenue as determined in accordance with U.S. GAAP. For a reconciliation of Net Energy Sales to revenue, see Renewable Energy Group - 2022 Renewable Energy Group Operating Results on page 31 of this MD&A.

Net Utility Sales

Net Utility Sales is a non-GAAP financial measure used by investors to identify utility revenue after commodity costs, either natural gas or electricity, where these commodity costs are generally included as a pass through in rates to its utility customers. AQN uses Net Utility Sales to assess its utility revenues without the effects of fluctuating commodity costs as such costs are predominantly passed through and paid for by utility customers. AQN believes that analysis and presentation of Net Utility Sales on this basis will enhance an investor’s understanding of the revenue generation of the Regulated Services Group. It is not intended to be representative of revenue as determined in accordance with U.S. GAAP. For a reconciliation of Net Utility Sales to revenue, see Regulated Services Group - 2022 Regulated Services Group Operating Results on page 21 of this MD&A.

Divisional Operating Profit

Divisional Operating Profit is a non-GAAP financial measure. AQN uses Divisional Operating Profit to assess the operating performance of its business groups without the effects of (as applicable): depreciation and amortization expense, corporate administrative expenses, income tax expense or recoveries, acquisition costs, certain litigation expenses, interest expense, gain or loss on derivative financial instruments, write down of intangibles and property, plant and equipment, gain or loss on foreign exchange, earnings or loss from discontinued operations (excluding the sale of assets in the course of normal operations), non-service pension and post-employment costs, financial impacts from the Market Disruption Event on the Company's Senate Wind Facility, and other typically non-recurring or unusual items. AQN adjusts for these factors as they may be non-cash, unusual in nature and are not factors used by management for evaluating the operating performance of the divisional units. Divisional Operating Profit is calculated inclusive of interest, dividend and equity income earned from indirect investments, and Hypothetical Liquidation at Book Value (“HLBV”) income, which represents the value of net tax attributes earned in the period from electricity generated by certain of its U.S. wind power and U.S. solar generation facilities. AQN believes that presentation of this measure will enhance an investor’s understanding of AQN’s divisional operating performance. Divisional Operating Profit is not intended to be representative of cash provided by operating activities or results of operations determined in accordance with U.S. GAAP, and can be impacted positively or negatively by these items. For a reconciliation of Divisional Operating Profit to revenue for AQN's main business units, see Regulated Services Group - 2022 Regulated Services Group Operating Results on page 21 and Renewable Energy Group - 2022 Renewable Energy Group Operating Results on page 31 of this MD&A.



Algonquin Power & Utilities Corp. - Management Discussion & Analysis			5

Overview and Business Strategy

AQN is incorporated under the Canada Business Corporations Act. AQN owns and operates a diversified portfolio of regulated and non-regulated generation, distribution, and transmission assets which are expected to deliver predictable earnings and cash flows. AQN seeks to maximize total shareholder value through new investments in renewable power generating facilities, regulated utilities and other complementary infrastructure projects, supported by the Company's focus on operational excellence and sustainability. Through these activities, the Company aims to drive growth in earnings and cash flows to support a sustainable dividend and share price appreciation. AQN strives to achieve these results while also seeking to maintain a business risk profile consistent with its BBB flat investment grade credit ratings and a strong focus on Environmental, Social and Governance factors.

In light of the current macroenvironment, including elevated interest and inflation rates, as well as Company specific challenges and the Company’s desire to effectively allocate capital and drive value creation for shareholders, the Company has reset the quarterly dividend to shareholders to $0.1085 per common share, or $0.4340 per common share on an annualized basis. AQN believes that, on a long-term basis, its targeted annual dividend payout will allow for both a return on investment for shareholders and retention of cash within AQN to partially fund growth opportunities. Changes in the level of dividends paid by AQN are at the discretion of AQN’s Board of Directors (the “Board”), with dividend levels being reviewed periodically by the Board in the context of AQN’s financial performance and growth prospects.

In addition, the Company has announced that it is targeting approximately $1 billion of asset sales (the "2023 Asset Recycling Plan") and that no new common equity financings are expected through the end of 2024.

AQN’s operations are organized across two primary business units consisting of: the Regulated Services Group, which primarily owns and operates a portfolio of regulated assets in the United States, Canada, Bermuda and Chile; and the Renewable Energy Group, which primarily operates a diversified portfolio of owned renewable generation assets.

AQN pursues investment opportunities with an objective of maintaining the current business mix between its Regulated Services Group and Renewable Energy Group and with leverage consistent with its current credit ratings.1 The business mix target may from time to time require AQN to grow its Regulated Services Group or implement other strategies in order to pursue investment opportunities within its Renewable Energy Group.

The Company also undertakes business development activities for both business units, primarily in North America, working to identify, develop, acquire, invest in, or divest of renewable energy facilities, regulated utilities and other complementary infrastructure projects.

Summary Structure of the Business

The following chart depicts, in summary form, AQN’s key businesses. A more detailed description of AQN’s organizational structure can be found in the most recent AIF.

1 See Treasury Risk Management -Downgrade in the Company's Credit Rating Risk.



Algonquin Power & Utilities Corp. - Management Discussion & Analysis			6

Regulated Services Group

The Regulated Services Group operates a diversified portfolio of regulated utility systems located in the United States, Canada, Bermuda and Chile serving approximately 1,244,000 customer connections as at December 31, 2022 (using an average of 2.5 customers per connection, this translates into approximately 3,110,000 customers). The Regulated Services Group seeks to provide safe, high quality, and reliable services to its customers and to deliver stable and predictable earnings to AQN. In addition to encouraging and supporting organic growth within its service territories, the Regulated Services Group seeks to deliver long-term growth through accretive acquisitions of additional utility systems and pursuing "greening the fleet" opportunities.

The Regulated Services Group's regulated electrical distribution utility systems and related generation assets are located in the U.S. States of California, New Hampshire, Missouri, Kansas, Oklahoma, and Arkansas, as well as in Bermuda, which together served approximately 309,000 electric customer connections as at December 31, 2022. The group also owns and operates generating assets with a gross capacity of approximately 2.0 GW and has investments in generating assets with approximately 0.3 GW of net generation capacity.

The Regulated Services Group's regulated water distribution and wastewater collection utility systems are located in the U.S. States of Arizona, Arkansas, California, Illinois, Missouri, New York, and Texas as well as in Chile which together served approximately 560,000 customer connections as at December 31, 2022.

The Regulated Services Group's regulated natural gas distribution utility systems are located in the U.S. States of Georgia, Illinois, Iowa, Massachusetts, New Hampshire, Missouri, and New York, and in the Canadian Province of New Brunswick, which together served approximately 375,000 natural gas customer connections as at December 31, 2022.

Below is a breakdown of the Regulated Services Group’s Revenue by geographic area for the twelve months ended December 31, 2022.



Algonquin Power & Utilities Corp. - Management Discussion & Analysis

Renewable Energy Group

The Renewable Energy Group operates, and directly owns interests in hydroelectric, wind, solar, renewable natural gas ("RNG") and thermal facilities with a combined gross generating capacity of approximately 2.5 GW and a net generating capacity (attributable to the Renewable Energy Group) of approximately 2.1 GW. Approximately 81% of the electrical output is sold pursuant to long term contractual arrangements which as of December 31, 2022 had a production-weighted average remaining contract life of approximately 11 years (see Market Price Risk).

In addition to the assets that the Renewable Energy Group operates, the Renewable Energy Group has investments in generating assets with approximately 1.4 GW of net generating capacity, which includes the Company’s 51% interest in the Texas Coastal Wind Facilities (as defined herein) and approximately 42% interest in Atlantica Sustainable Infrastructure plc (“Atlantica”). Atlantica owns and operates a portfolio of international clean energy and water infrastructure assets under long term contracts with a Cash Available for Distribution weighted average remaining contract life of approximately 14 years as of December 31, 2022.

Below is a breakdown of the Renewable Energy Group’s generating capacity by geographic area as of December 31, 2022, which was comprised of net generating capacity of facilities owned and operated and net generating capacity of investments, including the Company’s 51% interest in the Texas Coastal Wind Facilities and approximately 42% interest in Atlantica.



Algonquin Power & Utilities Corp. - Management Discussion & Analysis

Significant Updates

Operating Results

AQN operating results relative to the same period last year are as follows:


(all dollar amounts in $ millions except per share information)	Three months ended December 31			Twelve months ended December 31
	2022	2021	Change	2022	2021	Change
Net earnings (loss) attributable to shareholders	$(74.4)	$175.6	(142)%	$(212.0)	$264.9	(180)%
Adjusted Net Earnings1	$151.0	$137.0	10%	$474.9	$449.0	6%
Adjusted EBITDA1	$358.3	$298.3	20%	$1,256.8	$1,076.3	17%
Net earnings (loss) per common share	$(0.11)	$0.27	(141)%	$(0.33)	$0.41	(180)%
Adjusted Net Earnings per common share1	$0.22	$0.21	5%	$0.69	$0.71	(3)%


1			See Caution Concerning Non-GAAP Measures.

Declaration of 2023 First Quarter Dividend of $0.1085 (C$0.1495) per Common Share

AQN currently targets annual growth in dividends payable to shareholders underpinned by increases in earnings and cash flow.

The Board has declared a first quarter 2023 dividend of $0.1085 per common share payable on April 14, 2023 to shareholders of record on March 31, 2023.

The Canadian dollar equivalent for the first quarter 2023 dividend is C$0.1495 per common share.

The previous four quarter U.S. and Canadian dollar equivalent dividends per common share have been as follows:


	Q2 2022		Q3 2022		Q4 2022		Q1 2023		Total
U.S. dollar dividend	$	0.1808	$	0.1808	$	0.1808	$	0.1085	$0.6509
Canadian dollar equivalent	$	0.2345	$	0.2312	$	0.2438	$	0.1495	$0.8590

Pending Acquisition of Kentucky Power Company and AEP Kentucky Transmission Company, Inc.

On October 26, 2021, Liberty Utilities Co. (“Liberty Utilities”), an indirect subsidiary of AQN, entered into an agreement ("the Kentucky Acquisition Agreement") with American Electric Power Company, Inc. ("AEP") and AEP Transmission Company, LLC ("AEP Transmission") to acquire Kentucky Power Company (“Kentucky Power”) and AEP Kentucky Transmission Company, Inc. (“Kentucky TransCo”) for a total purchase price of approximately $2.846 billion, including the assumption of approximately $1.221 billion in debt (the “Kentucky Power Transaction”). On September 29, 2022, the parties entered into an amendment to the Kentucky Acquisition Agreement that, among other things, reduces the purchase price by $200 million to approximately $2.646 billion, including the assumption of approximately $1.221 billion in debt.

Kentucky Power is a state rate-regulated electricity generation, distribution and transmission utility serving customers in 20 eastern Kentucky counties and operating under a cost of service framework. Kentucky TransCo is an electricity transmission business operating in the Kentucky portion of the transmission infrastructure that is part of the Pennsylvania – New Jersey – Maryland regional transmission organization, PJM Interconnection, L.L.C. Kentucky Power and Kentucky TransCo are both regulated by the U.S. Federal Energy Regulatory Commission ("FERC").

Closing of the Kentucky Power Transaction remains subject to the satisfaction or waiver of certain conditions precedent, which include the approval of the Kentucky Power Transaction by FERC and clearance pursuant to the Hart-Scott-Rodino Antitrust Improvements Act of 1976 (as the clearance received previously has now lapsed). On December 15, 2022, FERC issued an order denying, without prejudice, authorization for the proposed transaction. On February 14, 2023, a new application was filed with FERC for approval of the Kentucky Power Transaction. If the Kentucky Power Transaction has not closed by April 26, 2023, either party may, if certain requirements are met, terminate the Kentucky Acquisition Agreement in accordance with its terms.

Inaugural Asset Recycling Transaction

On December 29, 2022, the Company closed the previously-announced sale of ownership interests in a portfolio of operating wind facilities in the United States and Canada to InfraRed Capital Partners, an international infrastructure investment manager that is part of SLC Management, the institutional alternatives and traditional asset management business of Sun Life Financial Inc. (the "Disposition Transaction"). The Disposition Transaction consisted of the sale of (1) a 49% ownership interest in three operating wind facilities in the United States totaling 551 MW of installed capacity: the Odell Wind Facility in Minnesota, the Deerfield Wind Facility in Michigan, and the Sugar Creek Wind Facility in Illinois; and



Algonquin Power & Utilities Corp. - Management Discussion & Analysis			9

(2) an 80% ownership interest in the operating 175 MW Blue Hill Wind Facility in Saskatchewan. Total cash proceeds to the Company were approximately $277.5 million for the U.S. facilities and approximately C$108.6 million for the Blue Hill Wind Facility (subject to certain potential future post-closing adjustments). A gain on disposition of $62.8 million was recognized and included in gain on sale of renewable assets on the Company's consolidated statement of operations. The Company will continue to oversee day-to-day operations and provide management services to the facilities.

Issuance of approximately $1.1 Billion of Subordinated Notes

On January 18, 2022, the Company closed (i) an underwritten public offering in the United States (the “U.S. Note Offering”) of $750 million aggregate principal amount of 4.75% fixed-to-fixed reset rate junior subordinated notes series 2022-B due January 18, 2082 (the “U.S. Notes”); and (ii) an underwritten public offering in Canada (the “Canadian Note Offering” and, together with the U.S. Note Offering, the “Note Offerings”) of C$400 million aggregate principal amount of 5.25% fixed-to-fixed reset rate junior subordinated notes series 2022-A due January 18, 2082 (the “Canadian Notes” and, together with the U.S. Notes, the “Notes”). The Company intends to use the net proceeds of the Note Offerings to partially finance the Kentucky Power Transaction, provided that, in the short-term, prior to closing of the Kentucky Power Transaction, the Company has used such net proceeds to repay certain indebtedness of the Corporation and its subsidiaries. As a result, the Company expects to draw from the credit facilities of the Company and certain of its subsidiaries in connection with the closing of the Kentucky Power Transaction. Concurrent with the pricing of the Note Offerings, the Company entered into a cross currency interest rate swap, to convert the Canadian dollar denominated proceeds from the Canadian Note Offering into U.S. dollars and a forward starting swap to fix the interest rate for the second five year term of the U.S. Notes, resulting in an anticipated effective interest rate to the Company of approximately 4.95% throughout the first ten year period of the Notes.

Acquisition of Liberty NY Water (formerly New York American Water Company, Inc.)

Effective January 1, 2022, Liberty Utilities (Eastern Water Holdings) Corp., a wholly-owned subsidiary of Liberty Utilities, closed the acquisition of Liberty Utilities (New York Water) Corp. (formerly New York American Water Company Inc.) ("Liberty NY Water") from American Water Works Company, Inc. for a purchase price of approximately $609 million. Headquartered in Merrick, NY, Liberty NY Water is a regulated water and wastewater utility serving approximately 127,000 customer connections across eight counties in southeastern New York. Liberty NY Water’s operations include approximately 1,270 miles of water mains and distribution lines, with 98% of customers located in Nassau County on Long Island. The Company has incorporated the operations of Liberty NY Water into its East Region.

Outlook

The following discussion should be read in conjunction with the Caution Concerning Forward-Looking Statements and Forward-Looking Information section in this MD&A. Actual results may differ materially from the estimates below. Accordingly, investors are cautioned not to place undue reliance on these estimates.

Estimated 2023 Adjusted Net Earnings Per Common Share

The Company estimates that its Adjusted Net Earnings per common share for the 2023 fiscal year will be within a range of $0.55-$0.61 (see Caution Concerning Non-GAAP Measures). Estimated 2023 Adjusted Net Earnings per common share is calculated excluding the impact of gains and losses from asset dispositions, but is otherwise calculated in a manner consistent with the description set out under Caution Concerning Non-GAAP Measures - Adjusted Net Earnings.

The Company’s 2023 Adjusted Net Earnings per common share estimate is based on the following key assumptions, as well as those set out under Caution Concerning Forward-Looking Statements and Forward-Looking Information:

•normalized weather patterns in the geographical areas in which the Company operates or has projects;

•renewable energy production consistent with long-term average and realized pricing in line with expectations;

•capital projects, including renewable energy generation projects, being completed on time and substantially in line with budgeted costs;

•the absence of significant changes in the macroeconomic environment, including with respect to interest rates and inflation;

•rate decisions in line with expectations;

•closing of the Kentucky Power Transaction in late April 2023;

•a Canadian dollar/U.S. dollar exchange rate and a Chilean Peso/U.S. dollar exchange rate in line with expectations;

•operating expense savings in line with expectations;

•a low single-digit percent effective tax rate, including tax credits and excluding an expected one-time 2017 tax reform adjustment related primarily to the Kentucky Power Transaction; and

•timing of the close of the 2023 Asset Recycling Plan in line with expectations.



Algonquin Power & Utilities Corp. - Management Discussion & Analysis

Capital Investment Expectations

Assuming closing of the $2.646 billion Kentucky Power Transaction, the Company anticipates making capital investments of approximately $3.6 billion in 2023. See Summary of Property, Plant and Equipment Expenditures for a more detailed discussion of the Company’s 2023 capital investment estimates.

In light of the current macroenvironment, including elevated interest and inflation rates, as well as Company specific challenges and the Company’s desire to effectively allocate capital, the Company expects reduced capital intensity from the Company's previously-disclosed expectation of $12.4 billion in capital investments for the period from 2022 through the end of 2026.



Algonquin Power & Utilities Corp. - Management Discussion & Analysis			11

2022 Fourth Quarter Results From Operations


Key Financial Information	Three months ended December 31
(all dollar amounts in $ millions except per share information)	2022		2021
Revenue	$	748.0	$	592.0

Net earnings (loss) attributable to shareholders	(74.4)		175.6
Cash provided by operating activities	214.6		126.5
Adjusted Net Earnings1	151.0		137.0
Adjusted EBITDA1	358.3		298.3
Adjusted Funds from Operations1	258.4		221.2
Dividends declared to common shareholders	123.7		115.5
Weighted average number of common shares outstanding	683,281,170		653,728,621
Per share

Basic net earnings (loss)	$	(0.11)	$	0.27
Diluted net earnings (loss)	$	(0.11)	$	0.26
Adjusted Net Earnings1	$	0.22	$	0.21
Dividends declared to common shareholders	$	0.18	$	0.17


1			See Caution Concerning Non-GAAP Measures.

For the three months ended December 31, 2022, AQN reported a basic net loss per common share of $0.11 as compared to basic net earnings per common share of $0.27 during the same period in 2021, a decrease of $0.38. This loss was primarily driven by the change in value of investments carried at fair value of $75.7 million primarily related to the Company's investment in Atlantica, and non-cash losses on asset impairment charges of $159.6 million, mainly on the Senate Wind Facility (which began commercial operations in 2012) due to declining forecasted energy prices in ERCOT, and an impairment of $75.9 million on the equity-method investment in the Texas Coastal Wind Facilities primarily as a result of continued challenges with congestion at the facilities (collectively the “2022 Impairment”).

For the three months ended December 31, 2022, AQN reported Adjusted Net Earnings per common share of $0.22 as compared to $0.21 per common share during the same period in 2021, an increase of $0.01 (see Caution Concerning Non-GAAP Measures). Adjusted Net Earnings increased by $14.0 million year over year. The Company grew year over year Adjusted EBITDA by $60.0 million (see Caution Concerning Non-GAAP Measures), primarily as a result of increased gains on asset sales of $33.7 million in the Renewable Energy Group, and the acquisition of Liberty NY Water, and implementation of new rates at the Empire, Bermuda and Granite State Electric Systems in the Regulated Services Group which contributed $10.1 million and $14.7 million of Adjusted EBITDA, respectively. This growth was partially offset by increased depreciation of $4.0 million, increased interest of $27.9 million, driven by higher interest rates as well as increased borrowings to support growth initiatives, lower recognition of investment tax credits (“ITCs”) and production tax credits (“PTCs”) of $9.4 million, and an increase in the weighted average number of common shares outstanding.

For the three months ended December 31, 2022, AQN experienced an average exchange rate of Canadian to U.S. dollars of approximately 0.7364 as compared to 0.7937 in the same period in 2021, and an average exchange rate of Chilean pesos to U.S. dollars of approximately 0.0011 for the three months ended December 31, 2022 as compared to 0.0012 for the same period in 2021. As such, any year over year variance in revenue or expenses, in local currency, at any of AQN’s Canadian and Chilean entities is affected by a change in the average exchange rate upon conversion to AQN’s reporting currency.

For the three months ended December 31, 2022, AQN reported total revenue of $748.0 million as compared to $592.0 million during the same period in 2021, an increase of $156.0 million or 26.4%. The major factors impacting AQN’s revenue in the three months ended December 31, 2022 as compared to the same period in 2021 are set out as follows:



Algonquin Power & Utilities Corp. - Management Discussion & Analysis			12


(all dollar amounts in $ millions)	Three months ended December 31
Comparative Prior Period Revenue	$	592.0
REGULATED SERVICES GROUP
Existing Facilities
Electricity: Increase is primarily due to higher pass through costs at the Empire and Granite State Electric Systems and favourable weather versus prior year at the Empire Electric System.	52.6
Natural Gas: Increase is primarily due to higher pass through commodity costs.	46.0
Water: Increase is primarily due to the inflationary rate increase mechanism at the ESSAL Water System and the tuck-in addition of the Bolivar Water System.	3.3
Other: Increase is primarily due to an increase in projects at Ft. Benning.	0.9
	102.8
New Facilities


Water: Acquisition of Liberty NY Water (January 2022).	30.8

	30.8
Rate Reviews
Electricity: Increase is primarily due to implementation of new rates at the Empire, Bermuda and Granite State Electric Systems.	11.5
Natural Gas: Increase is primarily due to implementation of new rates at the EnergyNorth and Peach State Gas Systems.	3.2

	14.7
Foreign Exchange	(2.1)



RENEWABLE ENERGY GROUP
Existing Facilities
Hydro: Increase is primarily due to higher production.	0.5
Wind Canada: Increase is primarily due to higher production at the St. Damase and Amherst Island Wind Facilities.	1.2
Wind U.S.: Increase is primarily due to favourable renewable energy certificate ("REC") revenue, favourable energy market pricing, as well as higher availability revenue at the Maverick and Sugar Creek Wind Facilities.	7.5
Solar: Decrease is primarily due to unfavourable weather conditions at the Great Bay I, Great Bay II, and Altavista Solar Facilities.	(1.7)

Thermal: Decrease is primarily driven by lower production at the Sanger Thermal Facility as it had reached the annual target limit of run hours.	(0.9)
Other: Increase is primarily due to higher Congestion Revenue Rights ("CRRs") revenue at the Texas Coastal Wind Facilities.	4.7
	11.3
New Facilities


Solar: Increase is due to the Croton Solar Facility (full commercial operations ("COD") in December 2021).	0.2
Other:	0.1
	0.3
Foreign Exchange	(1.8)

Current Period Revenue	$	748.0



Algonquin Power & Utilities Corp. - Management Discussion & Analysis

2022 Annual Results From Operations


Key Financial Information	Twelve months ended December 31
(all dollar amounts in $ millions except per share information)	2022		2021		2020
Revenue	$	2,765.2	$	2,274.1	$	1,677.0

Net earnings (loss) attributable to shareholders	(212.0)		264.9		782.5
Cash provided by operating activities	619.1		157.5		505.2
Adjusted Net Earnings1	474.9		449.0		365.8
Adjusted EBITDA1	1,256.8		1,076.3		869.5
Adjusted Funds from Operations1	864.1		757.9		600.2
Dividends declared to common shareholders	486.0		423.0		344.4
Weighted average number of common shares outstanding	677,862,207		622,347,677		559,633,275
Per share

Basic net earnings (loss)	$	(0.33)	$	0.41	$	1.38
Diluted net earnings (loss)	$	(0.33)	$	0.41	$	1.37
Adjusted Net Earnings1	$	0.69	$	0.71	$	0.64
Dividends declared to common shareholders	$	0.71	$	0.67	$	0.61
Total assets	17,627.6		16,797.5		13,224.1
Long term debt2	7,512.3		6,211.7		4,538.8


1			See Caution Concerning Non-GAAP Measures.


2			Includes current and long-term portion of debt and convertible debentures per the annual consolidated financial statements.

For the twelve months ended December 31, 2022, AQN reported a basic net loss per common share of $0.33 as compared to net earnings per common share of $0.41 during the same period in 2021, a decrease of $0.74. This loss was primarily driven by the change in value of investments carried at fair value of $376.7 million primarily related to the Company's investment in Atlantica, and the 2022 Impairment. These impaired assets operate within the ERCOT market, and the 2022 Impairment recorded is primarily due to declining forecasted energy prices in ERCOT for the Senate Wind Facility (which began commercial operations in 2012) and continued challenges with congestion at the Texas Costal Wind Facilities.

For the twelve months ended December 31, 2022, AQN reported Adjusted Net Earnings per common share of $0.69 as compared to $0.71 per share during the same period in 2021, a decrease of $0.02 (see Caution Concerning Non-GAAP Measures). Adjusted Net Earnings increased by $25.9 million year over year. The Company grew year over year Adjusted EBITDA by $180.5 million,(see Caution Concerning Non-GAAP Measures), primarily as a result of increased gains on asset sales of $34.9 million and $45.0 million in additional contributions from existing facilities in the Renewable Energy Group mainly driven by increased production, and the acquisition of Liberty NY Water and implementation of new rates at the Empire, Bermuda and Granite State Electric Systems in the Regulated Services Group which contributed $37.4 million and $42.3 million of Adjusted EBITDA, respectively. This growth was offset by increased depreciation of $52.5 million, increased interest expense of $69.0 million, driven by higher interest rates and higher borrowings to support growth initiatives, lower recognition of ITCs and PTCs of $31.0 million, and an increase in the weighted average number of common shares outstanding.

For the twelve months ended December 31, 2022, AQN experienced an average exchange rate of Canadian to U.S. dollars of approximately 0.7682 as compared to 0.7976 in the same period in 2021, and an average exchange rate of Chilean pesos to U.S. dollars of approximately 0.0011 for the twelve months ended December 31, 2022 as compared to 0.0014 for the same period in 2021. As such, any year-over-year variance in revenue or expenses, in local currency, at any of AQN’s Canadian and Chilean entities is affected by a change in the average exchange rate upon conversion to AQN’s reporting currency.

For the twelve months ended December 31, 2022, AQN reported total revenue of $2,765.2 million as compared to $2,274.1 million during the same period in 2021, an increase of $491.1 million or 21.6%. The major factors resulting in the increase in AQN revenue for the twelve months ended December 31, 2022 as compared to the same period in 2021 are as follows:



Algonquin Power & Utilities Corp. - Management Discussion & Analysis			14


(all dollar amounts in $ millions)	Twelve months ended December 31
Comparative Prior Period Revenue	$	2,274.1
REGULATED SERVICES GROUP
Existing Facilities
Electricity: Increase is primarily due to higher pass through costs at the Empire, Granite State and Bermuda Electric Systems and favourable weather at the Empire Electric System.	61.4
Natural Gas: Increase is primarily due to higher pass through commodity costs.	152.8
Water: Increase is primarily due to the inflationary rate increase mechanism at the ESSAL Water System.	15.2
Other: Increase is primarily due to an increase in projects at Ft. Benning.	1.1
	230.5
New Facilities


Water: Acquisition of Liberty NY Water (January 2022).	125.6

	125.6
Rate Reviews
Electricity: Increase is primarily due to implementation of new rates at the Empire, Bermuda and Granite State Electric Systems.	33.2
Natural Gas: Increase is primarily due to implementation of new rates at the EnergyNorth and Peach State Gas Systems.	7.3
Water: Increase is due to the implementation of new rates at the Park Water System.	1.8
	42.3
Foreign Exchange	(11.7)



RENEWABLE ENERGY GROUP
Existing Facilities
Hydro: Increase is primarily due to higher overall production as well as favourable pricing at one of the Company’s hydro facilities.	7.5
Wind Canada: Increase is primarily due to higher overall production.	5.0
Wind U.S.: Increase is primarily due to the non-recurring impact of the Market Disruption Event, higher production, favourable energy market pricing and favourable REC revenue across the U.S. wind facilities.	71.0
Solar: Increase is primarily due to favourable REC revenue at the Great Bay I Solar Facility and favourable energy market pricing at the Great Bay II Solar Facility.	2.7
Thermal: Increase is primarily due to favourable overall energy market pricing and favourable REC revenue at the Windsor Locks Thermal Facility.	11.9
Other: Increase is primarily due to higher CRR revenue at the Texas Coastal Wind Facilities.	8.2
	106.3
New Facilities

Wind U.S.: Decrease is driven by unfavourable pricing, partially offset by higher production at the Maverick Creek Wind Facility. This facility achieved partial completion on November 6, 2020 and COD on April 21, 2021.	(1.6)

Solar: Increase is primarily driven by the Altavista Solar Facility (full COD June 2021) and the Croton Solar Facility (full COD Dec 2021).	3.5
Other:	0.2
	2.1
Foreign Exchange	(4.0)

Current Period Revenue	$	2,765.2



Algonquin Power & Utilities Corp. - Management Discussion & Analysis

2022 Net Earnings Summary

Net loss attributable to shareholders for the three months ended December 31, 2022 totaled $74.4 million as compared to net earnings of $175.6 million during the same period in 2021, a decrease of $250.0 million or 142.4%. Net loss attributable to shareholders for the twelve months ended December 31, 2022 totaled $212.0 million as compared to net earnings of $264.9 million during the same period in 2021, a decrease of $476.9 million or 180.0%. The following table outlines the changes to net earnings (loss) attributable to shareholders for the three and twelve months ended December 31, 2022 as compared to the same periods in 2021. A more detailed analysis of these factors can be found under AQN: Corporate and Other Expenses.


Change in Net Earnings (loss) attributable to shareholders	Three months ended			Twelve months ended
	December 31			December 31
(all dollar amounts in $ millions)	2022			2022
Net earnings attributable to shareholders - Prior Period Balance	$	175.6		$	264.9
Adjusted EBITDA1	60.0			180.5
Net earnings attributable to the non-controlling interest, exclusive of HLBV	(3.7)			(2.8)
Income tax	30.4			18.1
Interest expense	(27.9)			(69.0)
Other net losses	9.8			1.5
Asset impairment charge	(159.6)			(159.6)
Impairment of equity-method investee	(75.9)			(75.9)
Unrealized loss (gain) on energy derivatives included in revenue	2.7			4.5
Pension and post-employment non-service costs	0.3			5.3
Change in value of investments carried at fair value	(75.7)			(376.7)
Impacts from the Market Disruption Event on the Senate Wind Facility	—			53.4
Costs related to tax equity financing	1.4			5.7
Loss on derivative financial instruments	5.3			—


Foreign exchange	(13.1)			(9.4)
Depreciation and amortization	(4.0)			(52.5)
Net loss attributable to shareholders - Current Period Balance	$	(74.4)		$	(212.0)

Change in Net Earnings ($)	$	(250.0)		$	(476.9)
Change in Net Earnings (%)	(142.4)		%	(180.0)		%


1			See Caution Concerning Non-GAAP Measures.

During the three months ended December 31, 2022, cash provided by operating activities totaled $214.6 million as compared to $126.5 million during the same period in 2021, an increase of $88.1 million. During the three months ended December 31, 2022, Adjusted Funds from Operations totaled $258.4 million as compared to Adjusted Funds from Operations of $221.2 million during the same period in 2021, an increase of $37.2 million (see Caution Concerning Non-GAAP Measures).

During the three months ended December 31, 2022, Adjusted EBITDA totaled $358.3 million as compared to $298.3 million during the same period in 2021, an increase of $60.0 million or 20.1% (see Caution Concerning Non-GAAP Measures). A more detailed analysis of this variance is presented within the reconciliation of Adjusted EBITDA to net earnings set out below under Non-GAAP Financial Measures.

During the twelve months ended December 31, 2022, cash provided by operating activities totaled $619.1 million as compared to $157.5 million during the same period in 2021, an increase of $461.6 million. During the twelve months ended December 31, 2022, Adjusted Funds from Operations totaled $864.1 million as compared to $757.9 million the same period in 2021, an increase of $106.2 million (see Caution Concerning Non-GAAP Measures).

During the twelve months ended December 31, 2022, Adjusted EBITDA totaled $1,256.8 million as compared to $1,076.3 million during the same period in 2021, an increase of $180.5 million or 16.8% (see Caution Concerning Non-



Algonquin Power & Utilities Corp. - Management Discussion & Analysis			16

GAAP Measures). A more detailed analysis of this variance is presented within the reconciliation of Adjusted EBITDA to net earnings set out below under Non-GAAP Financial Measures.

2022 Adjusted EBITDA Summary

Adjusted EBITDA (see Caution Concerning Non-GAAP Measures) for the three months ended December 31, 2022 totaled $358.3 million as compared to $298.3 million during the same period in 2021, an increase of $60.0 million or 20.1%. Adjusted EBITDA for the twelve months ended December 31, 2022 totaled $1,256.8 million as compared to $1,076.3 million during the same period in 2021, an increase of $180.5 million or 16.8%. The breakdown of Adjusted EBITDA by the Company's main business units and a summary of changes are shown below.


Adjusted EBITDA by business units	Three months ended December 31					Twelve months ended December 31
(all dollar amounts in $ millions)	2022			2021		2022			2021
Divisional Operating Profit for Regulated Services Group1	$	214.4		$	191.4	$	863.6		$	758.8
Divisional Operating Profit for Renewable Energy Group1	163.2			123.2		472.2			383.6
Administrative Expenses	(21.2)			(17.8)		(80.2)			(66.7)
Other Income & Expenses	1.9			1.5		1.2			0.6
Total AQN Adjusted EBITDA	$	358.3		$	298.3	$	1,256.8		$	1,076.3
Change in Adjusted EBITDA ($)	$	60.0				$	180.5
Change in Adjusted EBITDA (%)	20.1		%			16.8		%


1			See Caution Concerning Non-GAAP Measures.


Change in Adjusted EBITDA	Three months ended December 31, 2022
(all dollar amounts in $ millions)	Regulated Services		Renewable Energy		Corporate		Total
Prior period balances	$	191.4	$	123.2	$	(16.3)	$	298.3
Existing Facilities and Investments	(1.2)		9.5		0.4		8.7
New Facilities and Investments	10.1		(1.3)		—		8.8
Rate Reviews	14.7		—		—		14.7

Asset Dispositions	—		33.7		—		33.7
Foreign Exchange Impact	(0.6)		(1.9)		—		(2.5)
Administrative Expenses	—		—		(3.4)		(3.4)
Total change during the period	$	23.0	$	40.0	$	(3.0)	$	60.0
Current period balances	$	214.4	$	163.2	$	(19.3)	$	358.3


Change in Adjusted EBITDA	Twelve months ended December 31, 2022
(all dollar amounts in $ millions)	Regulated Services		Renewable Energy		Corporate		Total
Prior period balances	$	758.8	$	383.6	$	(66.1)	$	1,076.3
Existing Facilities and Investments	29.3		45.0		0.6		74.9
New Facilities and Investments	37.4		12.5		—		49.9
Rate Reviews	42.3		—		—		42.3

Asset Dispositions	—		34.9		—		34.9
Foreign Exchange Impact	(4.2)		(3.8)		—		(8.0)
Administrative Expenses	—		—		(13.5)		(13.5)
Total change during the period	$	104.8	$	88.6	$	(12.9)	$	180.5
Current period balances	$	863.6	$	472.2	$	(79.0)	$	1,256.8



Algonquin Power & Utilities Corp. - Management Discussion & Analysis

REGULATED SERVICES GROUP

The Regulated Services Group operates rate-regulated utilities that as of December 31, 2022 provided distribution services to approximately 1,244,000 customer connections in the electric, natural gas, and water and wastewater sectors which is an increase of approximately 151,000 customer connections as compared to December 31, 2021, including the approximately 127,000 customers in the state of New York that were added effective January 1, 2022 with the acquisition of Liberty NY Water.

The Regulated Services Group seeks to grow its business organically and through business development activities while using prudent acquisition criteria. The Regulated Services Group believes that its business results are maximized by building constructive regulatory and customer relationships, and enhancing customer connections in the communities in which it operates.


Utility System Type	As at December 31
	2022					2021
(all dollar amounts in $ millions)	Assets		Net Utility Sales1		Total Customer Connections2	Assets		Net Utility Sales1		Total Customer Connections2
Electricity	4,772.1		811.9		309,000	4,721.6		707.6		307,000
Natural Gas	1,728.9		345.9		375,000	1,573.4		331.7		373,000
Water and Wastewater	1,732.9		346.1		560,000	842.5		222.3		413,000


Other	321.0		55.7			256.7		53.4
Total	$	8,554.9	$	1,559.6	1,244,000	$	7,394.2	$	1,315.0	1,093,000

Accumulated Deferred Income Taxes Liability	$	689.1				$	600.2


1			Net Utility Sales for the twelve months ended December 31, 2022 and 2021. See Caution Concerning Non-GAAP Measures.
2			Total Customer Connections represents the sum of all active and vacant customer connections.

The Regulated Services Group aggregates the performance of its utility operations by utility system type – electricity, natural gas, and water and wastewater systems.

The electric distribution systems are comprised of regulated electrical distribution utility systems and served approximately 309,000 customer connections in the U.S. States of California, New Hampshire, Missouri, Kansas, Oklahoma and Arkansas and in Bermuda as at December 31, 2022.

The natural gas distribution systems are comprised of regulated natural gas distribution utility systems and served approximately 375,000 customer connections located in the U.S. States of New Hampshire, Illinois, Iowa, Missouri, Georgia, Massachusetts and New York and in the Canadian Province of New Brunswick as at December 31, 2022.

The water and wastewater distribution systems are comprised of regulated water distribution and wastewater collection utility systems and served approximately 560,000 customer connections located in the U.S. States of Arkansas, Arizona, California, Illinois, Missouri, New York, and Texas, and in Chile as at December 31, 2022.



Algonquin Power & Utilities Corp. - Management Discussion & Analysis			18

2022 Annual Usage Results


Electric Distribution Systems	Three months ended December 31			Twelve months ended December 31
	2022	2021		2022	2021
Average Active Electric Customer Connections For The Period
Residential	262,500	261,100	261100	261,900	260,600
Commercial and industrial	43,200	42,300		42,800	42,100
Total Average Active Electric Customer Connections For The Period	305,700	303,400		304,700	302,700

Customer Usage (GW-hrs)
Residential	653.3	581.7		2,899.6	2,769.7
Commercial and industrial	924.2	899.3		3,849.3	3,701.1
Total Customer Usage (GW-hrs)	1,577.5	1,481.0		6,748.9	6,470.8

For the three months ended December 31, 2022, the electric distribution systems' usage totaled 1,577.5 GW-hrs as compared to 1,481.0 GW-hrs for the same period in 2021, an increase of 96.5 GW-hrs or 6.5%. The increase in electricity consumption is primarily due to more favourable weather.

For the twelve months ended December 31, 2022, the electric distribution systems' usage totaled 6,748.9 GW-hrs as compared to 6,470.8 GW-hrs for the same period in 2021, an increase of 278.1 GW-hrs or 4.3%. The increase in electricity consumption is primarily due to more favourable weather.

Approximately 47% of the Regulated Services Group's electric distribution systems' revenues are not expected to be impacted by changes in customer usage, as they are subject to volumetric decoupling or represent fixed fee billings.


Natural Gas Distribution Systems	Three months ended December 31		Twelve months ended December 31
	2022	2021	2022	2021
Average Active Natural Gas Customer Connections For The Period
Residential	321,100	318,000	320,300	318,600
Commercial and industrial	39,100	38,100	38,800	38,100
Total Average Active Natural Gas Customer Connections For The Period	360,200	356,100	359,100	356,700

Customer Usage (MMBTU)
Residential	5,433,000	5,750,000	20,912,000	20,703,000
Commercial and industrial	5,723,000	5,077,000	20,607,000	18,696,000
Total Customer Usage (MMBTU)	11,156,000	10,827,000	41,519,000	39,399,000

For the three months ended December 31, 2022, usage at the natural gas distribution systems totaled 11,156,000 MMBTU as compared to 10,827,000 MMBTU during the same period in 2021, an increase of 329,000 MMBTU, or 3.0%. The increase in customer usage was primarily driven by customer growth in the New Brunswick Gas System and favourable weather at the Mid-States Gas System.

For the twelve months ended December 31, 2022, usage at the natural gas distribution systems totaled 41,519,000 MMBTU as compared to 39,399,000 MMBTU during the same period in 2021, an increase of 2,120,000 MMBTU or 5.4%. The increase in customer usage was primarily driven by favourable weather at the Mid-States, EnergyNorth and New Brunswick Gas Systems.

Approximately 86% of the Regulated Services Group's gas distribution systems' revenues are not expected to be impacted by changes in customer usage, as they are subject to volumetric decoupling or represent fixed fee billings.



Algonquin Power & Utilities Corp. - Management Discussion & Analysis			19


Water and Wastewater Distribution Systems	Three months ended December 31		Twelve months ended December 31
	2022	2021	2022	2021
Average Active Customer Connections For The Period
Wastewater customer connections	49,100	47,800	48,100	47,500
Water distribution customer connections	501,800	358,300	497,500	359,100
Total Average Active Customer Connections For The Period	550,900	406,100	545,600	406,600

Gallons Provided (millions of gallons)
Wastewater treated	822	726	3,233	2,768
Water provided	9,851	7,297	41,619	28,197
Total Gallons Provided (millions of gallons)	10,673	8,023	44,852	30,965

For the three months ended December 31, 2022, the water and wastewater distribution systems provided approximately 9,851 million gallons of water to customers and treated approximately 822 million gallons of wastewater. This is compared to 7,297 million gallons of water provided and 726 million gallons of wastewater treated during the same period in 2021, an increase in total gallons provided of 2,554 million or 35.0% and an increase in total gallons treated of 96 million or 13.2%. This is primarily due to the acquisition of Liberty NY Water.

For the twelve months ended December 31, 2022, the water and wastewater distribution systems provided approximately 41,619 million gallons of water to customers and treated approximately 3,233 million gallons of wastewater. This is compared to 28,197 million gallons of water provided and 2,768 million gallons of wastewater treated during the same period in 2021, an increase in total gallons provided of 13,422 million or 47.6% and an increase in total gallons treated of 465 million or 16.8%. This is primarily due to the acquisition of Liberty NY Water.

Approximately 50% of the Regulated Services Group's water and wastewater distribution systems' revenues are not expected to be impacted by changes in customer usage, as they are subject to volumetric decoupling or represent fixed fee billings.



Algonquin Power & Utilities Corp. - Management Discussion & Analysis

2022 Regulated Services Group Operating Results


	Three months ended December 31				Twelve months ended December 31
(all dollar amounts in $ millions)	2022		2021		2022		2021
Revenue
Regulated electricity distribution	$	326.3	$	261.3	$	1,277.4	$	1,183.4
Less: Regulated electricity purchased	(124.2)		(93.0)		(465.5)		(475.8)
Net Utility Sales - electricity1	202.1		168.3		811.9		707.6
Regulated gas distribution	221.8		172.0		686.7		525.9
Less: Regulated gas purchased	(125.5)		(80.2)		(340.8)		(194.2)
Net Utility Sales - natural gas1	96.3		91.8		345.9		331.7
Regulated water reclamation and distribution	89.0		58.3		364.4		234.9
Less: Regulated water purchased	(8.6)		(2.6)		(18.3)		(12.6)
Net Utility Sales - water reclamation and distribution1	80.4		55.7		346.1		222.3

Other revenue2	14.0		13.4		55.7		53.4
Net Utility Sales1,3	392.8		329.2		1,559.6		1,315.0
Operating expenses	(185.8)		(149.0)		(736.5)		(597.9)
Other income	5.2		3.9		21.9		18.3
HLBV4	2.2		7.3		18.6		23.4
Divisional Operating Profit1,5,6	$	214.4	$	191.4	$	863.6	$	758.8


1			See Caution Concerning Non-GAAP Measures.
2			See Note 21 in the annual consolidated financial statements.
3			This table contains a reconciliation of Net Utility Sales to revenue. The relevant sections of the table are derived from and should be read in conjunction with the consolidated statement of operations and Note 21 in the annual consolidated financial statements, “Segmented Information”. This supplementary disclosure is intended to more fully explain disclosures related to Net Utility Sales and provides additional information related to the operating performance of the Regulated Services Group. Investors are cautioned that Net Utility Sales should not be construed as an alternative to revenue.
4			HLBV income represents the value of net tax attributes monetized by the Regulated Services Group in the period at the Luning and Turquoise Solar Facilities and the Neosho Ridge, Kings Point and North Fork Ridge Wind Facilities (collectively the "Empire Wind Facilities").
5			This table contains a reconciliation of Divisional Operating Profit to revenue for the Regulated Services Group. The relevant sections of the table are derived from and should be read in conjunction with the consolidated statement of operations and Note 21 in the annual consolidated financial statements, “Segmented Information”. This supplementary disclosure is intended to more fully explain disclosures related to Divisional Operating Profit and provides additional information related to the operating performance of the Regulated Services Group. Investors are cautioned that Divisional Operating Profit should not be construed as an alternative to revenue.
6			Certain prior year items have been reclassified to conform with current year presentation.



Algonquin Power & Utilities Corp. - Management Discussion & Analysis			21

2022 Fourth Quarter Operating Results

For the three months ended December 31, 2022, the Regulated Services Group reported revenue of $637.0 million (i.e., $326.3 million of regulated electricity distribution, $221.8 million of regulated gas distribution and $89.0 million of regulated water reclamation and distribution) as compared to revenue of $491.6 million in the comparable period in the prior year (i.e., $261.3 million of regulated electricity distribution, $172.0 million of regulated gas distribution and $58.3 million of regulated water reclamation and distribution).

For the three months ended December 31, 2022, the Regulated Services Group reported a Divisional Operating Profit (excluding corporate administration expenses) of $214.4 million as compared to $191.4 million for the comparable period in the prior year (see Caution Concerning Non-GAAP Measures).

Highlights of the changes are summarized in the following table:


(all dollar amounts in $ millions)	Three months ended December 31
Prior Period Divisional Operating Profit1	$	191.4
Existing Facilities
Electricity: Increase is primarily due to favourable weather at the Empire Electric System.	5.4
Gas: Decrease is primarily due to higher operating expenses driven by inflationary pressure as well as increased bad debt, and property tax expenses.	(8.2)
Water: Decrease is primarily due to higher operating costs at the Park Water System.	(0.6)
Other:	2.2
	(1.2)
New Facilities


Water: Acquisition of Liberty NY Water (January 2022).	10.1

	10.1
Rate Reviews
Electricity: Increase is primarily due to implementation of new rates at the Empire, Bermuda and Granite State Electric Systems.	11.5
Gas: Increase is primarily due to implementation of new rates at the EnergyNorth and Peach State Gas Systems.	3.2

	14.7

Foreign Exchange	(0.6)


Current Period Divisional Operating Profit1	$	214.4


1			See Caution Concerning Non-GAAP Measures.



Algonquin Power & Utilities Corp. - Management Discussion & Analysis			22

2022 Annual Operating Results

For the twelve months ended December 31, 2022, the Regulated Services Group reported revenue of $2,328.5 million (i.e., $1,277.4 million of regulated electricity distribution, $686.7 million of regulated natural gas distribution and $364.4 million of regulated water reclamation and distribution) as compared to revenue of $1,944.2 million in the prior year (i.e., $1,183.4 million of regulated electricity distribution, $525.9 million of regulated natural gas distribution and $234.9 million of regulated water reclamation and distribution).

For the twelve months ended December 31, 2022, the Regulated Services Group reported a Divisional Operating Profit (excluding corporate administration expenses) of $863.6 million as compared to $758.8 million in the prior year (see Caution Concerning Non-GAAP Measures).

Highlights of the changes are summarized in the following table:


(all dollar amounts in $ millions)	Twelve months ended December 31
Prior Period Divisional Operating Profit1	$	758.8
Existing Facilities
Electricity: Increase is primarily due to higher than usual non-pass through fuel cost increases associated with the Midwest Extreme Weather Event that were recorded in the comparative period at the Empire Electric System and favourable weather at the Empire Electric System.	35.9
Natural Gas: Decrease is primarily due to higher operating expenses.	(9.6)
Water: Increase is primarily due to higher revenue at the ESSAL Water System.	0.3

Other: Increase is primarily due to increased carrying charges on regulatory assets.	2.7
	29.3
New Facilities


Water: Acquisition of Liberty NY Water (January 2022).	37.4

	37.4
Rate Reviews
Electricity: Increase is primarily due to implementation of new rates at the Empire, Bermuda and Granite State Electric Systems.	33.2
Natural Gas: Increase is primarily due to implementation of new rates at the EnergyNorth and Peach State Gas Systems.	7.3
Water: Increase is primarily due to the implementation of new rates at the Park Water System.	1.8
	42.3



Foreign Exchange	(4.2)
Current Period Divisional Operating Profit1	$	863.6


1			See Caution Concerning Non-GAAP Measures.



Algonquin Power & Utilities Corp. - Management Discussion & Analysis			23

Regulatory Proceedings

The following table summarizes the major regulatory proceedings currently underway or completed in 2022 within the Regulated Services Group.1

Utility

Jurisdiction

Regulatory Proceeding Type

Rate Request
(millions)

Current Status

Completed Rate Reviews

Empire Electric

Missouri

General Rate Case ("GRC") and Securitization

$79.9

On May 28, 2021, filed a rate review based on a 12 month historical test year ending September 30, 2020, with an update period through June 30, 2021, seeking to recover an annual revenue deficiency of $50.0 million, or a 7.61% increase in total base rate operating revenue, based on a rate base of $2.6 billion, which includes the Empire Wind Facilities and the retirement of the Asbury generating plant, and $29.9 million in costs associated with the impact of the Midwest Extreme Weather Event. On March 9, 2022 the Missouri Public Service Commission (the "MPSC") approved four stipulation agreements resolving all issues, except rate design, and resulting in an annual base rate revenue increase of $35.5 million, as well as another $4 million in revenues associated with the Empire Wind Facilities. On April 6, 2022, the MPSC issued its Report and Order resolving all issues. Empire Electric filed updated tariffs in May 2022 for new rates to become effective in June 2022.

On January 19, 2022, Empire Electric filed a petition for securitization of the costs associated with the impact of the Midwest Extreme Weather Event. On March 21, 2022, Empire Electric filed a petition for securitization of the costs associated with the retirement of the Asbury generating plant. On August 18, 2022, and September 22, 2022, the MPSC issued and amended, respectively, a Report and Order authorizing Empire Electric to securitize approximately $290.4 million in qualified extraordinary costs (Midwest Extreme Weather Event), energy transition costs (Asbury) and upfront financing costs associated with the proposed securitization. The amounts authorized by the securitization order are generally consistent with the costs deferred by the Company in relation to these matters. Empire Electric filed an appeal of the MPSC order on November 10, 2022. See – Regulatory Proceedings related to the Midwest Extreme Weather Event and the Retirement of Asbury for a more detailed description.

BELCO

Bermuda

GRC

$34.8

On September 30, 2021, BELCO filed its revenue allowance application in which it requested a $34.8 million increase for 2022 and a $6.1 million increase for 2023. On March 18, 2022, the Regulatory Authority (“RA”) approved an annual increase of $22.8 million, for a revenue allowance of $224.1 million for 2022 and $226.2 million for 2023. The RA authorized a 7.16% rate of return, comprised of a 62% equity and an 8.92% return on equity (“ROE”). In April 2022, BELCO filed an appeal in the Supreme Court of Bermuda challenging the decisions made by the RA through the recent Retail Tariff Review.



Algonquin Power & Utilities Corp. - Management Discussion & Analysis			24

Utility

Jurisdiction

Regulatory Proceeding Type

Rate Request
(millions)

Current Status

Empire Electric

Kansas

GRC

$4.5

On May 27, 2021, submitted an abbreviated rate review seeking to recover costs associated with the addition of the Empire Wind Facilities, the retirement of Asbury and non-growth related plant investments since the 2019 rate review. In May 2022, the Commission approved the unanimous partial settlement resolving the rate treatment of the Asbury retirement and the non-wind investments, and resulting in a base rate decrease of $0.6 million. Withdrawal of the request to recover the Empire Wind Facilities through base rates results in an estimated benefit to Empire Electric of $3.9 million. New base rates became effective in July 2022.

Empire District Gas Company

Missouri

GRC

$1.4

On August 23, 2021, filed an application requesting a revenue increase of $1.4 million based on an ROE of 10% and on a 52% equity capital structure. In January 2022, MPSC staff filed its testimony, recommending a $1.0 million revenue increase based on an ROE of 9.5%. On April 12, 2022 the Company, MPSC staff, consumer advocate group and industrial customer group filed a stipulation and agreement resolving most of the issues in the case. An evidentiary hearing was held in April 2022. In June 2022, the MPSC approved the stipulation and agreement providing for an annual increase of $1.0 million in base rate revenues. New rates became effective in August 2022.

Empire Electric

Oklahoma

GRC

$6.2

On February 28, 2022, filed an application seeking a base revenue increase of $6.2 million, offset by estimated fuel savings associated with the Empire Wind Facilities of $2.1 million, for an estimated net revenue increase of $4.1 million based on an ROE of 10% and a 52.79% equity capital structure. On December 29, 2022, the Commission approved a joint stipulation and agreement filed by the Company and Staff authorizing an annual base rate revenue increase of $5.1 million.

New Brunswick Gas

Canada

GRC

-$3.9

On November 22, 2021, filed its 2022 general rate application for a revenue decrease based on the Energy & Utilities Board's recent decision authorizing a capital structure of 45% equity and an ROE of 8.5%. In January 2022, New Brunswick Gas appealed the Energy & Utilities Board's cost of capital decision. In May 2022, the Energy & Utilities Board issued a partial decision approving a decrease in annual revenues of $1.0 million to become effective in July 2022. In June 2022, the Court of Appeal found in favour of New Brunswick Gas and remanded the cost of capital case back to the Energy & Utilities Board. On December 22, 2022 the Energy & Utilities Board issued a Final Order and approved an annual revenue increase of $1.3 million based on an ROE of 9.8%. New rates became effective January 1, 2023.

Apple Valley Ranchos Water System

California

GRC

$2.9

On July 2, 2021, filed an application requesting revenue increases of $2.9 million for 2022, $2.1 million for 2023, and $2.3 million for 2024 based on an ROE of 9.4% and on a 57% equity capital structure. The California Public Utilities Commission ("CPUC") Public Advocates Office issued its report in January 2022. Rebuttal testimony was filed in February 2022 and a hearing was held in March 2022. On February 3, 2023, the Commission issued a Final Order authorizing an annual revenue increase of $1.5 million. New rates are expected to become effective in March 2023 retroactive to July 1, 2022.



Algonquin Power & Utilities Corp. - Management Discussion & Analysis

Utility

Jurisdiction

Regulatory Proceeding Type

Rate Request
(millions)

Current Status

Park Water System

California

GRC

$5.5

On July 2, 2021, filed an application requesting revenue increases of $5.5 million for 2022, $1.8 million for 2023, and $1.8 million for 2024 based on an ROE of 9.4% and on a 57% equity capital structure. CPUC Public Advocates Office issued its report in January 2022. Rebuttal testimony was filed in February 2022 and a hearing was held in March 2022. On February 3, 2023, the CPUC issued a Final Order authorizing an annual revenue increase of $1.1 million. New rates will become effective in March 2023 retroactive to July 1, 2022.

Pending Rate Reviews

CalPeco Electric System

California

GRC

$35.7

On May 28, 2021, filed an application requesting a revenue increase of $35.7 million for 2022 based on an ROE of 10.5% and on a 54% equity capital structure. CPUC Public Advocates Office issued its report on February 23, 2022 and CalPeco filed its rebuttal testimony in March 2022. In May 2022, a settlement was reached resolving all issues except ROE. A final decision is expected in the second quarter of 2023.

St. Lawrence Gas

New York

GRC

$4.1

On November 24, 2021, filed an application requesting a revenue increase of $3.4 million based on an ROE of 10.5% and a capital structure of 50% equity. On January 31, 2022, filed a supplemental filing to update the requested revenue increase to $4.1 million. New York State Department of Public Service staff filed testimony on June 3, 2022 recommending an increase of $1.2 million in annual distribution revenues. St. Lawrence Gas filed rebuttal testimony on June 24, 2022 and updated request for an increase in distribution base revenues of $3.6 million. Settlement discussions began in July 2022 and a decision is expected in the second quarter of 2023.

Pine Bluff Water

Arkansas

GRC

$5.9

On September 30, 2022, filed an application seeking an increase in revenues of $5.9 million based on an ROE of 10.5% and an equity ratio of 52% to be phased in over three years.

Various

$0.1

Other pending rate review requests across two wastewater utilities.


1			All rate requests do not include step-up adjustments.



Algonquin Power & Utilities Corp. - Management Discussion & Analysis

Proceedings related to the Midwest Extreme Weather Event and the Retirement of Asbury

The Midwest Extreme Weather Event resulted in an extraordinary increase in costs incurred by Empire Electric for the purchase of fuel and power on behalf of its customers.

When Empire Electric filed its most recent Missouri rate case (the "Empire Rate Case") in May 2021, a request to recover the costs related to the Midwest Extreme Weather Event was included. In July 2021, Missouri House Bill 734 was signed into law, creating an option for utilities to finance the recovery of extraordinary weather event costs through securitization (the "Securitization Statute"). When it filed its surrebuttal testimony in January 2022, Empire Electric removed all costs related to the Midwest Extreme Weather Event from its rate request. Pursuant to the Securitization Statute, Empire Electric sought authorization for the issuance of approximately $222 million in securitized utility tariff bonds associated with the Midwest Extreme Weather Event.

In addition, as part of its 2017 and 2019 Integrated Resource Plans (“IRPs”), Empire Electric analyzed the effects of retiring Asbury, a coal-fired generation unit that was constructed in 1970, and determined that doing so would generate significant savings to customers. Asbury was retired on March 1, 2020. On July 23, 2020, the MPSC issued an Administrative Accounting Order ("AAO") that directed Empire Electric to establish regulatory asset and liability accounts, beginning January 1, 2020, to reflect the impact of the closure of Asbury on operating and capital expenses in Missouri.

Empire Electric initially sought to recover its Asbury related revenues and expenses, along with the balance of the AAO, in the Empire Rate Case. Following the passage of the Securitization Statute, all Asbury related balances were removed from the Empire Rate Case and, on March 21, 2022, Empire Electric filed a petition to securitize the Asbury related balances pursuant to the Securitization Statute. Empire Electric sought authority to issue approximately $141 million, in securitized utility tariff bonds for its Asbury costs, which include approximately $21 million in Asset Retirement Obligations, which are estimates of costs that Empire Electric will recover from the Asbury retirement but which have not yet been incurred.

On April 27, 2022, the MPSC issued an order consolidating, for purposes of hearing, the cases regarding the quantum financeable through securitization for Asbury and the Midwest Extreme Weather Event, which hearing was held the week of June 13, 2022. On August 18, 2022, and September 22, 2022, the MPSC issued and amended, respectively, a Report and Order authorizing Empire Electric to securitize approximately $290.4 million in qualified extraordinary costs (Midwest Extreme Weather Event), energy transition costs (Asbury) and upfront financing costs associated with the proposed securitization. The amounts authorized by the securitization order are generally consistent with the costs deferred by the Company in relation to these matters. Empire Electric filed a request for rehearing seeking reconsideration of the MPSC’s denial of recovery of five percent of the Midwest Extreme Weather Event costs, its calculation of accumulated deferred income taxes, and the exclusion of certain carrying charges associated with the Asbury plant, among other issues. On October 12, 2022, the MPSC denied all rehearing motions. Empire Electric appealed to the Missouri Court of Appeals – Western District on November 10, 2022. The Office of Public Counsel also filed an appeal, but withdrew that appeal on February 28, 2023. Briefing of the case is expected to be complete in April 2023.

Regulatory Proceedings related to Acquisitions:

Kentucky Power Transaction

Closing of the Kentucky Power Transaction is subject to receipt of certain regulatory and governmental approvals. During the first quarter of 2022, the applicable waiting period under the Hart-Scott-Rodino Antitrust Improvements Act of 1976 expired (which clearance has now lapsed) and the Committee on Foreign Investment in the United States cleared the Kentucky Power Transaction. On May 4, 2022, the Kentucky Public Service Commission (the "KPSC") issued an order approving the Kentucky Power Transaction, subject to certain conditions set forth in the order, including those agreed to by Liberty Utilities in the course of the docket. On May 3, 2022, the KPSC issued an order that required certain changes to the proposed operating and ownership agreements (collectively, the “Mitchell Agreements”) relating to the Mitchell coal generating facility (in which Kentucky Power owns a 50% interest, representing 780 MW) (the “Mitchell Plant”). On July 1, 2022, the Public Service Commission of West Virginia (the “WVPSC”) issued an order on the Mitchell Agreements that is inconsistent with the KPSC’s order on the Mitchell Agreements. The closing of the Kentucky Power Transaction is subject to the satisfaction or waiver of certain conditions precedent, which include the approval of the Kentucky Power Transaction by FERC, renewed clearance pursuant to the Hart-Scott-Rodino Antitrust Improvements Act of 1976 and those relating to the approval of the Mitchell Agreements by the KPSC, WVPSC and FERC. On September 29, 2022, Liberty Utilities, AEP and AEP Transmission entered into an amendment to the Kentucky Acquisition Agreement that provides a path towards closing. Among other things, the amendment reduces the purchase price by $200 million. On December 15, 2022, FERC issued an order denying, without prejudice, authorization for the proposed transaction. On February 14, 2023, a new application was filed with FERC for the approval of the Kentucky Power Transaction.



Algonquin Power & Utilities Corp. - Management Discussion & Analysis

RENEWABLE ENERGY GROUP


2022 Electricity Generation Performance
	Long Term Average Resource	Three months ended December 31		Long Term Average Resource	Twelve months ended December 31
(Performance in GW-hrs sold)		2022	2021		2022	2021
Hydro Facilities:
Maritime Region	37.6	48.2	36.7	148.2	149.1	124.2
Quebec Region	72.6	74.1	74.4	273.3	292.0	266.6
Ontario Region	26.2	27.9	21.8	120.4	116.0	91.2
Western Region	12.6	10.2	9.1	65.0	52.1	49.9
	149.0	160.4	142.0	606.9	609.2	531.9
Canadian Wind Facilities:
St. Damase	22.7	23.4	18.3	76.9	77.7	70.8
St. Leon	121.4	125.4	127.5	430.2	435.0	422.5
Red Lily1	24.1	25.3	26.3	88.5	90.8	91.2
Morse	30.5	26.1	31.0	108.8	103.7	107.2
Amherst	67.9	67.6	62.8	229.8	219.5	198.4
Blue Hill2	200.4	140.2	—	558.3	464.2	—
EBR3	21.0	21.1	—	74.4	71.0	—
	488.0	429.1	265.9	1,566.9	1,461.9	890.1
U.S. Wind Facilities:
Sandy Ridge	43.6	11.7	41.7	158.3	105.5	134.8
Minonk	189.8	208.5	194.7	673.7	696.9	622.1
Senate	140.0	114.2	144.1	520.4	490.0	480.5
Shady Oaks	100.5	114.9	100.7	355.6	362.2	319.2
Odell	238.0	250.9	214.7	831.8	869.3	720.3
Deerfield	167.9	168.8	150.8	546.0	554.9	515.9
Sugar Creek4	212.6	193.0	189.4	724.8	661.4	426.4
Maverick Creek5	480.2	362.6	483.0	1,920.6	1,620.9	1,519.2
	1,572.6	1,424.6	1,519.1	5,731.2	5,361.1	4,738.4
Solar Facilities:
Cornwall	2.2	2.4	2.1	14.7	14.7	14.6
Bakersfield	13.0	9.9	9.1	77.2	67.2	66.0
Great Bay	37.6	44.1	40.8	205.7	214.7	208.4
Altavista6	31.4	33.0	32.1	164.4	167.7	127.5
Croton7	0.9	1.1	0.2	5.4	5.4	0.2
	85.1	90.5	84.3	467.4	469.7	416.7
Renewable Energy Performance	2,294.7	2,104.6	2,011.3	8,372.4	7,901.9	6,577.1

Thermal Facilities:
Windsor Locks	N/A8	29.7	31.0	N/A7	127.5	128.8
Sanger	N/A8	—	34.5	N/A7	149.1	145.4
		29.7	65.5		276.6	274.2
Total Performance		2,134.3	2,076.8		8,178.5	6,851.3



Algonquin Power & Utilities Corp. - Management Discussion & Analysis			28


1			AQN owns a 75% equity interest but accounts for the facility using the equity method. Figures show full energy produced by the facility.
2			The Blue Hill Wind Facility achieved COD on April 14, 2022. AQN owns a 20% equity interest but accounts for the facility using the equity method. Figures show expected long-term average resources ("LTAR") and actual energy produced by the facility during the quarter.
3			The EBR Wind Facility achieved COD on December 31, 2021. AQN owns a 50% equity interest but accounts for the facility using the equity method. Figures show full energy produced by the facility.
4			The Sugar Creek Wind Facility achieved COD on November 9, 2020. Prior to January 29, 2021, AQN owned a 50% equity interest in the facility. On January 29, 2021, AQN acquired the remaining 50% equity interest that it did not previously own. Figures show full energy produced by the facility. As a result of a blade manufacturing error 26 of 40 turbines were initially shut down. All impacted turbines were back in service as of September 29, 2021.


5			The Maverick Creek Wind Facility achieved partial completion on November 6, 2020 and COD on April 21, 2021. Prior to January 19, 2021, AQN owned a 50% equity interest in the facility. On January 19, 2021, AQN acquired the remaining 50% equity interest that it did not previously own. Figures show full energy produced by the facility. As a result of a blade manufacturing error 26 of 73 turbines were initially shut down. All impacted turbines were back in service as of June 7, 2021.
6			The Altavista Solar Facility achieved partial completion on March 8, 2021 and COD on June 1, 2021. Prior to April 9, 2021, AQN owned a 50% equity interest in the facility. On April 9, 2021, AQN acquired the remaining 50% equity interest that it did not previously own. Figures show full energy produced by the facility.
7			The Croton Solar Facility achieved COD on December 8, 2021.
8			Natural gas fired co-generation facility.

2022 Fourth Quarter Renewable Energy Group Performance

For the three months ended December 31, 2022, the Renewable Energy Group generated 2,134.3 GW-hrs of electricity as compared to 2,076.8 GW-hrs during the same period in 2021.

For the three months ended December 31, 2022, the hydro facilities generated 160.4 GW-hrs of electricity as compared to 142.0 GW-hrs produced in the same period in 2021, an increase of 13.0%. Electricity generated represented 107.7% of LTAR as compared to 95.3% during the same period in 2021.

For the three months ended December 31, 2022, the wind facilities produced 1,853.7 GW-hrs of electricity as compared to 1,785.0 GW-hrs produced in the same period in 2021, an increase of 3.8%. The increase in production is primarily due to the addition of the EBR Wind Facility which achieved COD on December 31, 2021, and the Blue Hill Wind Facility which achieved COD on April 14, 2022. Excluding the Sugar Creek, EBR, and Blue Hill Wind Facilities, production was 6.0% below the same period last year. The wind facilities, including new facilities, generated electricity equal to 90.0% of LTAR as compared to 97.1% during the same period in 2021.

For the three months ended December 31, 2022, the solar facilities generated 90.5 GW-hrs of electricity as compared to 84.3 GW-hrs of electricity in the same period in 2021, an increase of 7.4%. The increase in production is partially due to the Croton Solar Facility achieving COD on December 8, 2021. Excluding the new facilities, production was 6.3% above the same period last year. The solar facilities, including new facilities, generated electricity equal to 106.3% of LTAR as compared to 99.9% in the same period in 2021.

For the three months ended December 31, 2022, the thermal facilities generated 29.7 GW-hrs of electricity as compared to 65.5 GW-hrs of electricity during the same period in 2021. During the same period, the Windsor Locks Thermal Facility generated 130.5 billion lbs of steam as compared to 132.1 billion lbs of steam during the same period in 2021.



Algonquin Power & Utilities Corp. - Management Discussion & Analysis			29

2022 Annual Renewable Energy Group Performance

For the twelve months ended December 31, 2022, the Renewable Energy Group generated 8,178.5 GW-hrs of electricity as compared to 6,851.3 GW-hrs during the same period in 2021.

For the twelve months ended December 31, 2022, the hydro facilities generated 609.2 GW-hrs of electricity as compared to 531.9 GW-hrs produced in the same period in 2021, an increase of 14.5%. Electricity generated represented 100.4% of LTAR as compared to 87.6% during the same period in 2021.

For the twelve months ended December 31, 2022, the wind facilities produced 6,823.0 GW-hrs of electricity as compared to 5,628.5 GW-hrs produced in the same period in 2021, an increase of 21.2%. The increase in production is primarily due to the addition of the Maverick Creek Wind Facility which achieved COD on April 21, 2021, the EBR Wind Facility which achieved COD on December 31, 2021, and the Blue Hill Wind Facility which achieved COD on April 14, 2022. In addition, the Sugar Creek Wind Facility and the Maverick Creek Wind Facility experienced lower production in 2021 due to the shutdown of turbines resulting from a blade manufacturing error. Excluding the new facilities, production was 8.8% above the same period last year. The wind facilities generated electricity equal to 93.5% of LTAR as compared to 90.1% during the same period in 2021.

For the twelve months ended December 31, 2022, the solar facilities generated 469.7 GW-hrs of electricity as compared to 416.7 GW-hrs of electricity produced in the same period in 2021, an increase of 12.7%. The increase in production is primarily due to the Altavista Solar Facility which achieved partial completion on March 8, 2021 and COD on June 1, 2021. In addition, the Croton Solar Facility achieved COD on December 8, 2021. Excluding the new facilities, production was 2.6% above the same period last year. The solar facilities generated electricity equal to 100.5% of LTAR as compared to 95.3% in the same period in 2021.

For the twelve months ended December 31, 2022, the thermal facilities generated 276.6 GW-hrs of electricity as compared to 274.2 GW-hrs of electricity during the same period in 2021. For the twelve months ended December 31, 2022, the Windsor Locks Thermal Facility generated 520.3 billion lbs of steam as compared to 507.0 billion lbs of steam during the same period in 2021.



Algonquin Power & Utilities Corp. - Management Discussion & Analysis			30


2022 Renewable Energy Group Operating Results
	Three months ended December 31				Twelve months ended December 31
(all dollar amounts in $ millions)	2022		2021		2022		2021
Revenue1
Hydro	$	11.7	$	8.5	$	51.6	$	36.8

Wind	65.9		59.8		221.4		156.4
Solar	2.8		5.6		29.9		26.9
Thermal	8.2		9.0		48.0		36.5
Total Non-Regulated Energy Sales	$	88.6	$	82.9	$	350.9	$	256.6
Less:

Cost of Sales - Energy2	(0.2)		(1.5)		(7.2)		(7.3)
Cost of Sales - Thermal	(5.2)		(7.0)		(34.5)		(23.9)

Net Energy Sales 3,4	$	83.2	$	74.4	$	309.2	$	225.4
Renewable Energy Credits5	7.6		3.7		27.8		17.5
Other Revenue	0.3		0.1		0.6		0.8
Total Net Revenue	$	91.1	$	78.2	$	337.6	$	243.7
Expenses & Other Income
Operating expenses	(31.7)		(24.8)		(114.5)		(104.3)
Gain on sale of renewable assets	62.8		29.1		64.0		29.1
Dividend, interest, equity and other income6	21.6		13.5		91.2		84.0
Impacts from the Market Disruption Event on the Senate Wind Facility	—		—		—		53.4
HLBV income7	19.4		27.2		93.9		77.7
Divisional Operating Profit3,8,9	$	163.2	$	123.2	$	472.2	$	383.6


1			Many of the Renewable Energy Group’s power purchase agreements ("PPAs") include annual rate increases. However, a change to the weighted average production levels resulting from higher average production from facilities that earn lower energy rates can result in a lower weighted average energy rate earned by the division as compared to the same period in the prior year. Includes the impacts from the Market Disruption Event on the Senate Wind Facility.
2			Cost of Sales - Energy consists of energy purchases in the Maritime Region to manage the energy sales from the Tinker Hydro Facility which is sold to retail and industrial customers under multi-year contracts.

3			See Caution Concerning Non-GAAP Measures.
4			This table contains a reconciliation of Net Energy Sales to revenue. The relevant sections of the table are derived from and should be read in conjunction with the consolidated statement of operations and Note 21 in the annual consolidated financial statements, “Segmented information”. This supplementary disclosure is intended to more fully explain disclosures related to Net Energy Sales and provides additional information related to the operating performance of AQN. Investors are cautioned that Net Energy Sales should not be construed as an alternative to revenue.
5			Qualifying renewable energy projects receive RECs for the generation and delivery of renewable energy to the power grid. The RECs represent proof that 1 MW-hr of electricity was generated from an eligible energy source.
6			Includes dividends received from Atlantica and related parties (see Notes 8 and 16 in the annual consolidated financial statements) as well as the equity investment in the Stella, Cranell, East Raymond and West Raymond Wind Facilities (collectively, the "Texas Coastal Wind Facilities").
7			HLBV income represents the value of net tax attributes earned by the Renewable Energy Group in the period primarily from electricity generated by certain of its U.S. wind and U.S. solar generation facilities. PTCs are earned as wind energy is generated based on a dollar per kW-hr rate prescribed in applicable federal and state statutes. For the twelve months ended December 31, 2022, the Renewable Energy Group's eligible facilities generated 4,998.9 GW-hrs representing approximately $125.0 million in PTCs earned as compared to 2,473.6 GW-hrs representing $61.8 million in PTCs earned during the same period in 2021. The majority of the PTCs have been allocated to tax equity investors to monetize the value to AQN of the PTCs and other tax attributes which are the primary drivers of HLBV income offset by the return earned by the investor. Some PTCs have been utilized directly by the Company to lower its overall effective tax rate.
8			Certain prior year items have been reclassified to conform to current year presentation.
9			This table contains a reconciliation of Divisional Operating Profit to revenue for the Renewable Energy Group. The relevant sections of the table are derived from and should be read in conjunction with the consolidated statement of operations and Note 21 in the annual consolidated financial statements, “Segmented Information”. This supplementary disclosure is intended to more fully explain disclosures related to Divisional Operating Profit and provides additional information related to the operating performance of the Renewable Energy Group. Investors are cautioned that Divisional Operating Profit should not be construed as an alternative to revenue.



Algonquin Power & Utilities Corp. - Management Discussion & Analysis			31

2022 Fourth Quarter Operating Results

For the three months ended December 31, 2022, the Renewable Energy Group’s facilities generated operating revenue of $88.6 million (i.e., non-regulated energy sales) as compared to $82.9 million in the comparable period in the prior year.

For the three months ended December 31, 2022, the Renewable Energy Group's facilities generated $163.2 million of Divisional Operating Profit as compared to $123.2 million during the same period in 2021, which represents an increase of $40.0 million or 32.5% (see Caution Concerning Non-GAAP Measures).

Highlights of the changes are summarized in the following table:


(all dollar amounts in $ millions)	Three months ended December 31
Prior Period Divisional Operating Profit1	$	123.2
Existing Facilities and Investments
Hydro: Increase is primarily due to higher overall production.	1.6
Wind Canada: Increase is primarily due to higher production at the St. Damase and Amherst Island Wind Facilities.	1.0
Wind US: Decrease is primarily due to lower HLBV income as a result of lower production, and higher operating expenses across the U.S. wind facilities partially offset by favourable renewable energy certificate ("REC") revenue, favourable energy market pricing, as well as higher availability revenue at the Maverick and Sugar Creek Wind Facilities.	(5.2)

Solar: Decrease is primarily due to unfavourable weather conditions at the Great Bay I, Great Bay II, and Altavista Solar Facilities.	(1.2)

Thermal: Increase is primarily driven by favourable energy market pricing at the Windsor Locks Thermal Facility.	0.7
Investments: Decrease is primarily due to timing of dividends from the Company's investments.2	(0.9)
Other: Increase is primarily due to higher equity income from the Texas Coastal Wind Facilities and the Val-Eo Wind Facility.	13.5
	9.5
New Facilities and Investments




Solar: Increase is primarily due to Croton Solar Facility (full COD in December 2021).	0.3

Other: Decrease is primarily due to start-up costs at the RNG facilities.	(1.6)
	(1.3)
Asset Dispositions	33.7

Foreign Exchange	(1.9)
Current Period Divisional Operating Profit1	$	163.2


1			See Caution Concerning Non-GAAP Measures.
2			See Notes 8 and 16 in the annual consolidated financial statements.



Algonquin Power & Utilities Corp. - Management Discussion & Analysis			32

2022 Annual Operating Results

For the twelve months ended December 31, 2022, the Renewable Energy Group's facilities generated operating revenue of $350.9 million (i.e., non-regulated energy sales) as compared to $256.6 million in the comparable period in the prior year.

For the twelve months ended December 31, 2022, the Renewable Energy Group's facilities generated $472.2 million of Divisional Operating Profit as compared to $383.6 million during the same period in 2021, which represents an increase of $88.6 million or 23.1% (see Caution Concerning Non-GAAP Measures).

Highlights of the changes are summarized in the following table:


(all dollar amounts in $ millions)	Twelve months ended December 31
Prior Period Divisional Operating Profit1	$	383.6
Existing Facilities
Hydro: Increase is primarily due to higher overall production as well as favourable pricing at one of the Company's hydro facilities.	4.6
Wind Canada: Increase is primarily due to higher overall production.	4.8
Wind U.S.: Increase is primarily due to higher production, favourable energy market pricing, REC revenue and HLBV income.	19.3

Solar: Increase is primarily due to favourable REC revenue at the Great Bay I Solar Facility.	0.7

Thermal: Increase is primarily due to favourable overall energy market pricing and favourable REC revenue at the Windsor Locks Thermal Facility.	1.7
Investments: Increase is primarily due to higher dividends from AQN's investment in Atlantica.2	5.7
Other: Increase is primarily due to higher equity income from the Val-Eo Wind Facility.	8.2
	45.0
New Facilities and Investments


Wind U.S.: Increase is primarily due to higher production, higher HLBV income partially offset by unfavourable pricing at the Maverick Creek Wind Facility. This facility achieved partial completion on November 6, 2020 and COD on April 21, 2021.	11.3

Solar: Increase is primarily due to the Great Bay II Solar Facility (full COD in August 2020), the Altavista Solar Facility (full COD in June 2021), and the Croton Solar Facility (full COD in December 2021).	2.3

Other: Decrease is primarily due to start-up costs at the RNG facilities.	(1.1)
	12.5
Asset Dispositions	34.9

Foreign Exchange	(3.8)
Current Period Divisional Operating Profit1	$	472.2


1			See Caution Concerning Non-GAAP Measures.
2			See Notes 8 and 16 in the annual consolidated financial statements.



Algonquin Power & Utilities Corp. - Management Discussion & Analysis			33

AQN: CORPORATE AND OTHER EXPENSES


	Three months ended December 31				Twelve months ended December 31
(all dollar amounts in $ millions)	2022		2021		2022		2021
Corporate and other expenses:
Administrative expenses	$	21.2	$	17.8	$	80.2	$	66.7
Loss on foreign exchange	14.1		1.0		13.8		4.4

Interest expense	78.0		50.1		278.6		209.6
Depreciation and amortization	114.8		110.8		455.5		403.0
Change in value of investments carried at fair value	14.7		(61.0)		499.1		122.4
Interest, dividend, equity, and other loss1	17.7		0.6		3.2		6.4
Pension and other post-employment non-service costs	4.6		4.9		11.0		16.3
Other net losses	2.1		11.9		21.4		22.9

Gain on derivative financial instruments	(6.4)		(1.1)		(4.4)		(4.4)
Income tax expense (recovery)	(28.6)		1.8		(61.5)		(43.4)


1			Excludes income directly pertaining to the Regulated Services and Renewable Energy Groups (disclosed in the relevant sections).

2022 Fourth Quarter Corporate and Other Expenses

For the three months ended December 31, 2022, administrative expenses totaled $21.2 million as compared to $17.8 million in the same period in 2021. The increase was primarily due to higher staffing expenses as a result of increased headcount to support growth initiatives and drive operational excellence, and inflationary increases.

For the three months ended December 31, 2022, interest expense totaled $78.0 million as compared to $50.1 million in the same period in 2021 due to the funding of capital deployed in 2022 primarily related to the acquisition of Liberty NY Water and the development of renewable energy projects as well as an increase in interest rates on variable rate borrowings.

For the three months ended December 31, 2022, depreciation expense totaled $114.8 million as compared to $110.8 million in the same period in 2021. The increase was primarily due to higher overall property, plant and equipment and the acquisition of Liberty NY Water.

For the three months ended December 31, 2022, change in investments carried at fair value totaled a loss of $14.7 million as compared to a gain of $61.0 million in the same period in 2021. The Company records certain of its investments, including Atlantica, using the fair value method and accordingly any change in the fair value of the investment is recorded in the consolidated statement of operations (see Note 8 in the annual consolidated financial statements).

For the three months ended December 31, 2022, pension and post-employment non-service costs totaled $4.6 million as compared to $4.9 million in the same period in 2021. The decrease was primarily due to lower amortization of actuarial losses.

For the three months ended December 31, 2022, other net losses were $2.1 million as compared to $11.9 million in the same period in 2021. The decrease was primarily due to timing of acquisition and transition-related costs. See Note 19 in the annual consolidated financial statements.

For the three months ended December 31, 2022, the gain on derivative financial instruments totaled $6.4 million as compared to a gain of $1.1 million in the same period in 2021. AQN uses derivative instruments to manage exposure to changes in commodity prices, foreign exchange rates, and interest rates. The gain in the fourth quarter of both 2022 and 2021 was primarily related to mark-to-markets on interest rate derivatives.

For the three months ended December 31, 2022, an income tax recovery of $28.6 million was recorded as compared to an income tax expense of $1.8 million during the same period in 2021. The decrease in income tax expense was primarily due to the tax benefits associated with the 2022 Impairment and the change in fair value of the investment in Atlantica. These tax recoveries were partially offset by the valuation allowance recorded on the Renewable Energy Group and lower tax credits accrued. For the three months ended December 31, 2022, the Company accrued $4.7 million of ITCs and PTCs primarily associated with renewable energy projects that were placed in service by the end of 2022 as compared to $14.1 million recorded in the same period in 2021.



Algonquin Power & Utilities Corp. - Management Discussion & Analysis			34

2022 Annual Corporate and Other Expenses

During the twelve months ended December 31, 2022, administrative expenses totaled $80.2 million as compared to $66.7 million in the same period in 2021. The increase was primarily due to higher staffing expenses as a result of increased headcount to support growth initiatives and drive operational excellence, and inflationary increases.

For the twelve months ended December 31, 2022, interest expense totaled $278.6 million as compared to $209.6 million in the same period in 2021. The increase was primarily due to the funding of capital deployed in 2022 primarily related to the acquisition of Liberty NY Water and the development of renewable energy projects as well as an increase in interest rates on variable rate borrowings.

For the twelve months ended December 31, 2022, depreciation expense totaled $455.5 million as compared to $403.0 million in the same period in 2021. The increase was primarily due to higher overall property, plant and equipment and the acquisition of Liberty NY Water.

For the twelve months ended December 31, 2022, change in investments carried at fair value totaled a loss of $499.1 million as compared to a loss of $122.4 million in the same period in 2021. The Company records certain of its investments, including Atlantica, using the fair value method and accordingly any change in the fair value of the investment is recorded in the consolidated statement of operations (see Note 8 in the annual consolidated financial statements).

For the twelve months ended December 31, 2022, pension and post-employment non-service costs totaled $11.0 million as compared to $16.3 million in the same period in 2021. The decrease was primarily due to lower amortization of actuarial losses.

For the twelve months ended December 31, 2022, other net losses were $21.4 million as compared to $22.9 million in the same period in 2021. The net losses for the twelve months ended December 31, 2022 were primarily due acquisition and transition-related costs. The net losses for the twelve months ended December 31, 2021 were primarily due to acquisition and transition-related costs, an adjustment to a regulatory liability pertaining to the true-up of prior period tracking accounts and certain asset write-downs.

For the twelve months ended December 31, 2022, the gain on derivative financial instruments totaled $4.4 million as compared to a gain of $4.4 million in the same period in 2021. AQN uses derivative instruments to manage exposure to changes in commodity prices, foreign exchange rates, and interest rates. The gain for both the twelve months ended December 31, 2022 and for the twelve months ended December 31, 2021 were primarily related to mark-to-markets on interest rate derivatives.

For the twelve months ended December 31, 2022, an income tax recovery of $61.5 million was recorded as compared to an income tax recovery of $43.4 million during the same period in 2021. The increase in income tax recovery was primarily due to the tax benefits associated with the 2022 Impairment and change in fair value of the investment in Atlantica. These tax recoveries were partially offset by the valuation allowance recorded on the Renewable Energy Group, lower tax credits accrued, the tax impact of the Midwest Extreme Weather Event in 2021, and remeasurement of state deferred tax adjustments related to the acquisition of Liberty NY Water. For the twelve months ended December 31, 2022, the Company accrued $18.4 million of ITCs and PTCs primarily associated with renewable energy projects that were placed in service by the end of 2022 as compared to $49.4 million recorded in the same period in 2021.



Algonquin Power & Utilities Corp. - Management Discussion & Analysis			35

NON-GAAP FINANCIAL MEASURES

Reconciliation of Adjusted EBITDA to Net Earnings

The following table is derived from and should be read in conjunction with the consolidated statement of operations. This supplementary disclosure is intended to more fully explain disclosures related to Adjusted EBITDA and provides additional information related to the operating performance of AQN. Investors are cautioned that this measure should not be construed as an alternative to U.S. GAAP consolidated net earnings.


	Three months ended December 311				Twelve months ended December 31
(all dollar amounts in $ millions)	2022		2021		2022		2021
Net earnings (loss) attributable to shareholders	$	(74.4)	$	175.6	$	(212.0)	$	264.9
Add (deduct):
Net earnings attributable to the non-controlling interest, exclusive of HLBV	6.0		2.3		18.9		16.1

Income tax expense (recovery)	(28.6)		1.8		(61.5)		(43.4)

Interest expense	78.0		50.1		278.6		209.6
Other net losses2	2.1		11.9		21.4		22.9
Unrealized loss (gain) on energy derivatives included in revenue	(2.1)		0.6		0.9		5.4
Asset impairment charge	159.6		—		159.6		—
Impairment of equity-method investee	75.9		—		75.9		—
Pension and post-employment non-service costs	4.6		4.9		11.0		16.3

Change in value of investments carried at fair value3	14.7		(61.0)		499.1		122.4
Impacts from the Market Disruption Event on the Senate Wind Facility	—		—		—		53.4
Costs related to tax equity financing	—		1.4		—		5.7
Gain on derivative financial instruments	(6.4)		(1.1)		(4.4)		(4.4)


Loss on foreign exchange	14.1		1.0		13.8		4.4
Depreciation and amortization	114.8		110.8		455.5		403.0
Adjusted EBITDA4	$	358.3	$	298.3	$	1,256.8	$	1,076.3


1			Amounts for the three months ended December 31, 2022 and 2021 are derived by subtracting the Company's results for the nine months ended September 30, 2022 and 2021 from the Company's 2022 and 2021 annual results, respectively.

2			See Note 19 in the annual consolidated financial statements.
3			See Note 8 in the annual consolidated financial statements.
4			Amounts for the three and twelve months ended December 31, 2022 include $62.8 million and $64.0 million, respectively, in gains from asset dispositions. Amounts for the three and twelve months ended December 31, 2021 include $29.1 million and $29.1 million, respectively, in gains from asset dispositions.



Algonquin Power & Utilities Corp. - Management Discussion & Analysis			36

Reconciliation of Adjusted Net Earnings to Net Earnings

The following table is derived from and should be read in conjunction with the consolidated statement of operations. This supplementary disclosure is intended to more fully explain disclosures related to Adjusted Net Earnings and provides additional information related to the operating performance of AQN. Investors are cautioned that this measure should not be construed as an alternative to consolidated net earnings in accordance with U.S. GAAP.

The following table shows the reconciliation of net earnings to Adjusted Net Earnings exclusive of these items:


	Three months ended December 311				Twelve months ended December 31
(all dollar amounts in $ millions except per share information)	2022		2021		2022		2021
Net earnings (loss) attributable to shareholders	$	(74.4)	$	175.6	$	(212.0)	$	264.9
Add (deduct):

Gain on derivative financial instruments	(6.4)		(1.1)		(4.4)		(4.4)


Other net losses2	2.1		11.9		21.4		22.9
Asset impairment charge	159.6		—		159.6		—
Impairment of equity-method investee	75.9		—		75.9		—
Loss on foreign exchange	14.1		1.0		13.8		4.4

Unrealized loss (gain) on energy derivatives included in revenue	(2.1)		0.6		0.9		5.4
Change in value of investments carried at fair value3	14.7		(61.0)		499.1		122.4
Impacts from the Market Disruption Event on the Senate Wind Facility	—		—		—		53.4
Costs related to tax equity financing and other adjustments	—		1.4		—		5.7

Adjustment for taxes related to above	(32.5)		8.6		(79.4)		(25.7)
Adjusted Net Earnings4	$	151.0	$	137.0	$	474.9	$	449.0
Adjusted Net Earnings per common share	$	0.22	$	0.21	$	0.69	$	0.71


1			Amounts for the three months ended December 31, 2022 and 2021 are derived by subtracting the Company's results for the nine months ended September 30, 2022 and 2021 from the Company's 2022 and 2021 annual results, respectively.
2			See Note 19 in the annual consolidated financial statements.
3			See Note 8 in the annual consolidated financial statements.
4			Amounts for the three and twelve months ended December 31, 2022 include $53.4 million and $54.3 million, respectively, in gains from asset dispositions after tax. Amounts for the three and twelve months ended December 31, 2021 include $21.1 million and $21.1 million, respectively, in gains from asset dispositions after tax.

For the three months ended December 31, 2022, Adjusted Net Earnings totaled $151.0 million as compared to Adjusted Net Earnings of $137.0 million for the same period in 2021, an increase of $14.0 million.

For the twelve months ended December 31, 2022, Adjusted Net Earnings totaled $474.9 million as compared to Adjusted Net Earnings of $449.0 million for the same period in 2021, an increase of $25.9 million.



Algonquin Power & Utilities Corp. - Management Discussion & Analysis			37

Reconciliation of Adjusted Funds from Operations to Cash Provided by Operating Activities

The following table is derived from and should be read in conjunction with the consolidated statement of operations and consolidated statement of cash flows. This supplementary disclosure is intended to more fully explain disclosures related to Adjusted Funds from Operations and provides additional information related to the operating performance of AQN. Investors are cautioned that this measure should not be construed as an alternative to cash provided by operating activities in accordance with U.S GAAP.

The following table shows the reconciliation of cash provided by operating activities to Adjusted Funds from Operations exclusive of these items:


	Three months ended December 311				Twelve months ended December 31
(all dollar amounts in $ millions)	2022		2021		2022		2021
Cash provided by operating activities	$	214.6	$	126.5	$	619.1	$	157.5
Add (deduct):
Changes in non-cash operating items	41.2		84.4		221.6		522.0

Production based cash contributions from non-controlling interests	—		—		6.2		4.8

Impacts from the Market Disruption Event on the Senate Wind Facility	—		—		—		53.4
Costs related to tax equity financing	—		0.5		(0.2)		5.7
Acquisition-related costs	2.6		9.8		17.4		14.5

Adjusted Funds from Operations2	$	258.4	$	221.2	$	864.1	$	757.9


1			Amounts for the three months ended December 31, 2022 and 2021 are derived by subtracting the Company's results for the nine months ended September 30, 2022 and 2021 from the Company's 2022 and 2021 annual results, respectively.
2			Amounts for the three and twelve months ended December 31, 2022 include $62.8 million and $64.0 million, respectively, in gains from asset dispositions. Amounts for the three and twelve months ended December 31, 2021 include $29.1 million and $29.1 million, respectively, in gains from asset dispositions.

For the three months ended December 31, 2022, Adjusted Funds from Operations totaled $258.4 million as compared to Adjusted Funds from Operations of $221.2 million for the same period in 2021, an increase of $37.2 million.

For the twelve months ended December 31, 2022, Adjusted Funds from Operations totaled $864.1 million as compared to Adjusted Funds from Operations of $757.9 million for the same period in 2021, an increase of $106.2 million.



Algonquin Power & Utilities Corp. - Management Discussion & Analysis			38

SUMMARY OF PROPERTY, PLANT, AND EQUIPMENT EXPENDITURES


	Three months ended December 31				Twelve months ended December 31
(all dollar amounts in $ millions)	2022		2021		2022		2021
Regulated Services Group
Rate Base Maintenance1	78.5		$	73.5	316.5		279.3
Rate Base Growth	253.5		172.7		669.1		1,670.3
Property, Plant & Equipment Acquired2	—		—		609.3		—
	$	332.0	$	246.2	$	1,594.9	$	1,949.6

Renewable Energy Group
Maintenance1	$	23.4	$	10.5	$	41.1	$	46.0
Investment in Capital Projects2	80.0		24.9		135.5		1,676.3

	$	103.4	$	35.4	$	176.6	$	1,722.3


Total Capital Expenditures	$	435.4	$	281.6	$	1,771.5	$	3,671.9


1			Maintenance expenditures are calculated based on the depreciation expense for the period.
2			Includes expenditures on Property Plant & Equipment, equity-method investees, and acquisitions of operating entities that may have been jointly developed by the Company with another third party developer. Excludes temporary advances to joint venture partners in connection with capital projects under development or construction.

2022 Fourth Quarter Property Plant and Equipment Expenditures

During the three months ended December 31, 2022, the Regulated Services Group invested $332.0 million in capital expenditures as compared to $246.2 million during the same period in 2021. The Regulated Services Group's investments during the fourth quarter of 2022 were primarily related to the construction of transmission and distribution main replacements, work on new and existing substation assets, and initiatives relating to the safety and reliability of electric and natural gas systems.

During the three months ended December 31, 2022, the Renewable Energy Group incurred capital expenditures of $103.4 million as compared to $35.4 million during the same period in 2021. The Renewable Energy Group's investments during the fourth quarter of 2022 were primarily related to the development and/or construction of ongoing maintenance capital at existing operating sites.

2022 Annual Property Plant and Equipment Expenditures

During the twelve months ended December 31, 2022, the Regulated Services Group invested $1,594.9 million in capital expenditures as compared to $1,949.6 million during the same period in 2021. The Regulated Services Group's investments in 2022 were primarily related to the acquisition of Liberty NY Water in January 2022. In addition, during 2022, the Regulated Services Group invested in the construction of transmission and distribution main replacements, work on new and existing substation assets, and initiatives relating to the safety and reliability of electric and natural gas systems.

During the twelve months ended December 31, 2022, the Renewable Energy Group incurred capital expenditures of $176.6 million as compared to $1,722.3 million during the same period in 2021. The Renewable Energy Group's investment in 2021 was primarily related to the acquisitions of the previously unowned portions of the Maverick Creek and Sugar Creek Wind Projects and the Altavista Solar Project from its joint venture partners, as well as the acquisition of a 51% interest in the Texas Coastal Wind Facilities. The Renewable Energy Group's investments during 2022 were primarily related to the development and/or construction of various projects and ongoing sustaining capital at existing operating sites.



Algonquin Power & Utilities Corp. - Management Discussion & Analysis			39

2023 Capital Investments

The following discussion should be read in conjunction with the Caution Concerning Forward-Looking Statements and Forward-Looking Information section of this MD&A.

Assuming the closing of the $2.646 billion Kentucky Power Transaction the Company expects to spend approximately $3.6 billion on capital investment opportunities in the 2023 fiscal year. Actual expenditures in 2023 may vary due to, among other things, the timing of project investments and acquisitions, the availability of financing on acceptable terms, and realized foreign exchange rates.

The Regulated Services Group expects to spend approximately $3.3 billion over the course of 2023. This includes the $2.646 billion Kentucky Power Transaction. The remaining Regulated Services Group spend is expected to contribute to continued efforts to expand operations, improve the reliability of the utility systems and broaden the technologies used to better serve its service areas. Project spending includes capital for structural improvements, specifically in relation to refurbishing substations, replacing poles and wires, drilling and equipping aquifers, main replacements, and reservoir pumping stations.

The Renewable Energy Group expects to spend approximately $300 million over the course of 2023 to (i) develop or further invest in development and construction (as applicable) of the Renewable Energy Group's wind, solar, and renewable natural gas projects. and (ii) with respect to various operational solar, thermal, hydro and wind assets to comply with safety regulations and drive operational efficiencies.



Algonquin Power & Utilities Corp. - Management Discussion & Analysis			40

LIQUIDITY AND CAPITAL RESERVES

AQN has revolving credit and letter of credit facilities as well as separate credit facilities for the Regulated Services Group and the Renewable Energy Group to manage the liquidity and working capital requirements of each division (collectively the “Bank Credit Facilities”).

Bank Credit Facilities

The following table sets out the Bank Credit Facilities available to AQN and its operating groups as at December 31, 2022:


	As at December 31, 2022											As at December 31, 2021
(all dollar amounts in $ millions)	Corporate			Regulated Services Group			Renewable Energy Group			Total		Total
Revolving and term credit facilities	$	550.0	1	$	2,863.3	2	$	1,100.0	3	$	4,513.3	$	3,217.0
Funds drawn on facilities/ commercial paper issued	(180.1)			(1,275.0)			(77.4)			(1,532.5)		(849.6)
Letters of credit issued	(34.7)			(37.0)			(393.5)			(465.2)		(317.2)
Liquidity available under the facilities	335.2			1,551.3			629.1			2,515.6		2,050.2
Undrawn portion of uncommitted letter of credit facilities	(18.8)			—			(208.1)			(226.9)		(224.0)
Cash on hand										57.6		125.2
Total Liquidity and Capital Reserves	$	316.4		$	1,551.3		$	421.0		$	2,346.3	$	1,951.4

1 Includes a $50 million uncommitted standalone letter of credit facility.
2 Includes $163.3 million fully drawn term facilities of ESSAL and Bermuda as at December 31, 2022 ($142 million as at December 31, 2021).
3 Includes $600 million of uncommitted standalone letter of credit facilities.

Corporate

As at December 31, 2022, the Company's $500.0 million senior unsecured syndicated revolving credit facility (the "Corporate Credit Facility") had $180.1 million drawn and had $3.5 million of outstanding letters of credit. The Corporate Credit Facility matures on July 12, 2024.

As at December 31, 2022, the Company had also issued $31.2 million of letters of credit from its $50 million uncommitted bi-lateral letter of credit facility.

Regulated Services Group

On April 29, 2022, the Regulated Services Group entered into two new senior unsecured syndicated revolving credit facilities: a $1.0 billion senior unsecured revolving credit facility with an initial maturity date of April 29, 2027 (the "Long Term Regulated Services Credit Facility") and a $500.0 million short-term senior unsecured revolving credit facility maturing on March 31, 2023 (the "Short Term Regulated Services Credit Facility"). Subsequent to year-end this facility was extended to February 28, 2024.

As at December 31, 2022, the Long Term Regulated Services Credit Facility had no amounts drawn and had $37.0 million of outstanding letters of credit. As at December 31, 2022, the Short Term Regulated Services Credit Facility had no amounts drawn and no outstanding letters of credit. As at December 31, 2022, there was $407.0 million of commercial paper issued and outstanding.

As at December 31, 2022, the Regulated Services Group's $75.0 million senior unsecured revolving credit facility (the "Bermuda Credit Facility") had $74.3 million drawn. On December 23, 2022, the Regulated Services Group amended and restated its $75.0 million Bermuda Credit Facility with a new maturity date of December 31, 2024. On June 24, 2022, the Regulated Services Group entered into a new $25.0 million senior unsecured bilateral revolving credit facility (the "Bermuda Working Capital Facility") that matures on June 24, 2024. As at December 31, 2022, the Bermuda Working Capital Facility had $20.0 million drawn.



Algonquin Power & Utilities Corp. - Management Discussion & Analysis			41

On November 30, 2022, the Regulated Services Group amended and restated its $1.1 billion senior unsecured syndicated delayed draw term facility ("the "Regulated Services Delayed Draw Term Facility") with the new maturity date of November 29, 2023. As at December 31, 2022, the Regulated Services Delayed Draw Term Facility had $610.4 million drawn.

Renewable Energy Group

On July 22, 2022, the Renewable Energy Group amended and restated its $500.0 million senior unsecured syndicated revolving credit facility (the "Renewable Energy Credit Facility") with a new maturity date of July 22, 2027. Subject to the terms and conditions therein, the Renewable Energy Credit Facility may be extended for additional one-year periods.

As at December 31, 2022, the Renewable Energy Group's bank lines consisted of $600.0 million letter of credit facilities (the "Renewable Energy LC Facilities"), including a new $250.0 million uncommitted bilateral letter of credit facility that was entered into on July 22, 2022, and a $350.0 million uncommitted letter of credit facility that was amended and restated on November 8, 2022 with a new maturity date of June 30, 2024.

As at December 31, 2022, the Renewable Energy Credit Facility had $77.4 million drawn and had $1.6 million in outstanding letters of credit. As at December 31, 2022, the Renewable Energy LC Facilities had $391.9 million in outstanding letters of credit.

Long Term Debt

On February 15, 2022, the Company repaid a C$200.0 million senior unsecured note on its maturity.

On April 30, 2022, the Company repaid a $80.0 million senior unsecured note on its maturity.

On August 1, 2022, the Company repaid a $115.0 million senior unsecured note on its maturity.

Subsequent to year end, the Company repaid a $15,000 senior unsecured note on its maturity.

Issuance of approximately $1.1 Billion of Subordinated Notes

On January 18, 2022, the Company closed (i) an underwritten public offering in the United States of $750 million aggregate principal amount of the U.S. Notes; and (ii) an underwritten public offering in Canada of C$400 million aggregate principal amount of the Canadian Notes. Concurrent with the pricing of the Note Offerings, the Company entered into a cross currency interest rate swap to convert the Canadian dollar denominated proceeds from the Canadian Note Offering into U.S. dollars and a forward starting swap to fix the interest rate for the second five year term of the U.S. Notes, resulting in an anticipated effective interest rate to the Company of approximately 4.95% throughout the first ten year period of the Notes. The Note Offerings were assigned a BB+ rating from S&P and Fitch (each as defined herein).

The Company intends to use the net proceeds of the Note Offerings to partially finance the Kentucky Power Transaction, provided that, in the short-term, prior to the closing of the Kentucky Power Transaction, the Company has used such net proceeds to repay certain indebtedness of the Corporation and its subsidiaries.

Credit Ratings

AQN has a long term consolidated corporate credit rating of BBB from Standard & Poor’s Financial Services LLC, (“S&P”), a BBB rating from DBRS Limited (“DBRS”) and a BBB issuer rating from Fitch Ratings Inc. (“Fitch”). Liberty Utilities has a corporate credit rating of BBB from S&P, a BBB issuer rating from Fitch and a Baa2 issuer rating from Moody’s Investor Service, Inc. (“Moody's”). Debt issued by Liberty Utilities Finance GP1 (“Liberty GP”) has a rating of BBB (high) from DBRS, BBB+ from Fitch, BBB from S&P and Baa2 from Moody's. Empire has an issuer rating of BBB from S&P and a Baa1 rating from Moody's. Liberty Utilities (Canada) LP, the parent company for the Canadian regulated utilities under the Regulated Services Group, has an issuer rating of BBB from DBRS. Algonquin Power Co. ("APCo") has a BBB issuer rating from S&P, a BBB issuer rating from DBRS and a BBB issuer rating from Fitch.

On October 28, 2021, following the announcement of the Kentucky Power Transaction, each of DBRS, Fitch and S&P made announcements regarding the credit ratings of the Corporation and its subsidiaries.

Fitch affirmed (i) the existing issuer ratings of both the Corporation and Liberty Utilities (‘BBB’ Long-Term Issuer Default Rating (“IDR”) and ‘F2’ Short-Term IDR, respectively), and (ii) all the security ratings of the Corporation, Liberty Utilities and Liberty GP. Fitch also noted that the rating outlooks for the Corporation and Liberty Utilities are stable and that the credit ratings of APCo are unaffected by the Kentucky Power Transaction. Fitch noted that it views the Kentucky Power Transaction to be neutral to the credit quality of the Corporation and Liberty Utilities, given the underlying credit quality of Kentucky Power, and what Fitch expects to be a relatively credit-supportive financing plan for the Kentucky Power Transaction. During the first quarter of 2023, Fitch affirmed its existing ratings and outlook.

In 2022, DBRS placed the Corporation’s ‘BBB’ Issuer Rating and ‘Pfd-3’ Preferred Shares ratings ‘Under Review with Developing Implications’. DBRS indicated that it viewed the Kentucky Power Transaction as a positive development from a business risk perspective due to the expected increase in the Corporation’s regulated assets and rate base and expected improvements in jurisdictional diversification and capital expenditure planning. Notwithstanding these potentially positive



Algonquin Power & Utilities Corp. - Management Discussion & Analysis			42

impacts, the ‘Under Review with Developing Implications’ rating action reflected DBRS’s view that the Corporation’s financing plan for the Kentucky Power Transaction could increase the Corporation’s nonconsolidated leverage. Subsequent to year-end in February 2023, DBRS affirmed its existing ratings on APUC, APCo and Liberty GP and removed APUC from “Under Review with Developing Implications”, updating the outlook to stable.

In 2022, S&P revised its outlook on the Corporation, Liberty Utilities, APCo, Liberty GP and Empire from stable to negative, noting a lack of certainty regarding the Corporation’s financing plan for the Kentucky Power Transaction, beyond the equity offering for gross proceeds of approximately C$800 million undertaken to partially finance the Kentucky Power Transaction, which could expose the Corporation to execution risks related to the procurement of credit supportive funding. S&P also noted that the negative outlook incorporated the possibility of any material adverse regulatory requirements which may be necessary to close the Kentucky Power Transaction. S&P also affirmed its ‘BBB’ issuer credit rating for each of the Corporation, Liberty Utilities, APCo, Liberty GP and Empire. Finally, S&P placed its rating on Liberty GP’s senior unsecured debt on CreditWatch with negative implications to reflect its view of the potential for such debt to be structurally subordinated following the closing of the Kentucky Power Transaction.

In 2022, S&P removed the "CreditWatch with negative implications" from Liberty GP's senior unsecured debt. During the first quarter of 2023, S&P affirmed these ratings and outlook, noting that its negative outlook reflects the execution risk associated with the Company's 2023 Asset Recycling Plan.

Contractual Obligations

Information concerning contractual obligations as of December 31, 2022 is shown below:


(all dollar amounts in $ millions)	Total		Due in less than 1 year		Due in 1 to 3 years		Due in 4 to 5 years		Due after 5 years
Principal repayments on debt obligations1,2	$	7,537.3	$	1,416.2	$	404.6	$	1,984.9	$	3,731.6

Advances in aid of construction	88.5		1.6		—		—		86.9
Interest on long-term debt obligations2	5,080.9		310.9		447.2		386.6		3,936.2
Purchase obligations	741.9		741.9		—		—		—
Environmental obligations	48.3		9.3		18.1		1.9		19.0
Derivative financial instruments:
Cross currency interest rate swaps	39.8		3.2		5.5		6.3		24.8


Energy derivative and commodity contracts	130.5		29.3		49.6		29.9		21.7
Purchased power	322.4		89.8		65.2		24.8		142.6
Gas delivery, service and supply agreements	512.5		113.8		138.7		71.8		188.2
Service agreements	575.8		67.5		113.7		96.1		298.5
Capital projects	7.2		7.2		—		—		—
Land easements	531.4		13.3		26.8		27.5		463.8
Contract adjustment payments on equity units	113.9		76.2		37.7		—		—
Other obligations	320.6		37.2		6.4		5.1		271.9
Total Obligations	$	16,051.0	$	2,917.4	$	1,313.5	$	2,634.9	$	9,185.2


1			Exclusive of deferred financing costs, bond premium/discount, and fair value adjustments at the time of issuance or acquisition.
2			The Company's subordinated unsecured notes have a maturity in 2078, 2079, and 2082, respectively. However, the Company currently anticipates repaying such notes in 2023, 2029, and 2032, respectively, upon exercising its redemption right.

Equity

The common shares of AQN are publicly traded on the Toronto Stock Exchange ("TSX") and the New York Stock Exchange ("NYSE") under the trading symbol "AQN". As at March 15, 2023, AQN had 688,203,107 issued and outstanding common shares.

AQN may issue an unlimited number of common shares. The holders of common shares are entitled to dividends, if and when declared; to one vote for each share at meetings of the holders of common shares; and to receive a pro rata share of any remaining property and assets of AQN upon liquidation, dissolution or winding up of AQN. All shares are of the same class and with equal rights and privileges and are not subject to future calls or assessments.



Algonquin Power & Utilities Corp. - Management Discussion & Analysis

•4,800,000 cumulative rate reset Series A preferred shares, yielding 5.162% annually for the five-year period ending on December 31, 2023;

•100 Series C preferred shares that were issued in exchange for 100 Class B limited partnership units by St. Leon Wind Energy LP; and

•4,000,000 cumulative rate reset Series D preferred shares, yielding 5.091% annually for the five year period ending on March 31, 2024.

In addition, AQN’s outstanding equity units (the "Green Equity Units") (that are in the form of "corporate units") are listed on the NYSE under the ticker symbol "AQNU". As at March 15, 2023, there were 23,000,000 Green Equity Units outstanding. Pursuant to the purchase contract forming part of each outstanding Green Equity Unit, holders are required to purchase AQN common shares on June 15, 2024. The minimum settlement rate under each purchase contract is 2.7778 common shares and the maximum settlement rate is 3.3333 common shares, resulting in a minimum of 63,889,400 common shares and a maximum of 76,665,900 common shares issuable on settlement of the purchase contracts.

At-The-Market Equity Program

On August 15, 2022, AQN re-established an at-the-market equity program (“ATM Program”) that allows the Company to issue up to $500 million of common shares from treasury to the public from time to time, at the Company’s discretion, at the prevailing market price when issued on the TSX, the NYSE or any other existing trading market for the common shares of the Company in Canada or the United States.

During the three months ended December 31, 2022, the Company did not issue any common shares under its ATM Program. On January 12, 2023, AQN announced that no new common equity financings were expected through the end of 2024.

During the twelve months ended December 31, 2022, the Company issued 2,861,709 common shares under its ATM Program at an average price of $13.94 per common share for gross proceeds of approximately $38.9 million (approximately $38.5 million net of commissions). Other related costs were $0.6 million.

As at March 16, 2023, the Company has issued, since the inception of its initial ATM Program in 2019, a cumulative total of 36,814,536 common shares at an average price of $15.00 per share for gross proceeds of approximately $551.1 million (approximately $544.3 million net of commissions). Other related costs, primarily related to the establishment and subsequent re-establishments of the ATM Program, were approximately $4.8 million.

Dividend Reinvestment Plan

AQN has a shareholder dividend reinvestment plan (the “Reinvestment Plan”) for registered holders of common shares of AQN. As at December 31, 2022, 142,304,835 common shares representing approximately 21% of total common shares outstanding had been registered with the Reinvestment Plan. During the three months ended December 31, 2022, 2,508,889 common shares were issued under the Reinvestment Plan, and subsequent to quarter-end, on January 13, 2023, an additional 4,370,289 common shares were issued under the Reinvestment Plan.

Effective March 16, 2023, AQN suspended the Reinvestment Plan. Effective for the first quarter 2023 dividend (payable on April 14, 2023 to shareholders of record on March 31, 2023), shareholders participating in the Reinvestment Plan will begin receiving cash dividends. If the Company elects to reinstate the Reinvestment Plan in the future, shareholders who were enrolled in the Reinvestment Plan at its suspension and remain enrolled at reinstatement will automatically resume participation in the Reinvestment Plan.

SHARE-BASED COMPENSATION PLANS

For the twelve months ended December 31, 2022, AQN recorded $10.9 million in total share-based compensation expense as compared to $8.4 million for the same period in 2021. The compensation expense is recorded as part of operating expenses in the consolidated statement of operations. The portion of share-based compensation costs capitalized as cost of construction is insignificant.

As at December 31, 2022, total unrecognized compensation costs related to non-vested share-based awards was $10.7 million and is expected to be recognized over a period of 1.8 years.

Stock Option Plan

AQN has a stock option plan that permits the grant of share options to officers, directors, employees and selected service providers. Except in certain circumstances, the term of an option shall not exceed ten (10) years from the date of the grant of the option.

AQN determines the fair value of options granted using the Black-Scholes option-pricing model. The estimated fair value of options, including the effect of estimated forfeitures, is recognized as an expense on a straight-line basis over the options’



Algonquin Power & Utilities Corp. - Management Discussion & Analysis			44

vesting periods while ensuring that the cumulative amount of compensation cost recognized at least equals the value of the vested portion of the award at that date. During the twelve months ended December 31, 2022, the Company granted 646,090 options to executives of the Company. The options allow for the purchase of common shares at a weighted average price of $19.11, the market price of the underlying common share at the date of grant. During the twelve months ended December 31, 2022, executives of the Company exercised 40,074 stock options at a weighted average exercise price of $13.92 in exchange for 3,999 common shares issued from treasury and 36,075 options were settled in cash as payment for the exercise price and tax withholdings related to the exercise of the options.

As at December 31, 2022, a total of 2,626,780 options were issued and outstanding under the stock option plan.

Performance and Restricted Share Units

AQN issues performance share units (“PSUs”) and restricted share units ("RSUs") to certain employees as part of AQN’s long-term incentive program. During the twelve months ended December 31, 2022, the Company granted (including dividends and performance adjustments) a combined total of 1,090,457 PSUs and RSUs to employees of the Company. During the twelve months ended December 31, 2022, the Company settled 1,221,620 PSUs, of which 611,772 PSUs were exchanged for common shares issued from treasury and 609,848 PSUs were settled at their cash value as payment for tax withholdings related to the settlement of the PSUs.

As at December 31, 2022, a combined total of 2,109,710 PSUs and RSUs were granted and outstanding under the performance and restricted share unit plan.

Directors' Deferred Share Units

AQN has a Directors' Deferred Share Unit Plan. Under the plan, non-employee directors of AQN receive all or any portion of their annual compensation in deferred share units (“DSUs”) and may elect to receive any portion of their remaining compensation in DSUs. The DSUs provide for settlement in cash or common shares at the election of AQN. As AQN does not expect to settle the DSUs in cash, these DSUs are accounted for as equity awards. During the twelve months ended December 31, 2022, the Company issued 120,513 DSUs (including DSUs in lieu of dividends) to the non-employee directors of the Company. During the twelve months ended December 31, 2022, the Company settled 5,176 DSUs, of which 2,403 DSUs were exchanged for common shares issued from treasury and 2,773 DSUs were settled at their cash value as payment for tax withholdings related to the settlement of DSUs.

As at December 31, 2022, a total of 645,714 DSUs were outstanding under the Directors’ Deferred Share Unit Plan.

Bonus Deferral Restricted Share Units

The Company has a bonus deferral RSU program that is available to certain employees. The eligible employees have the option to receive a portion or all of their annual bonus payment in RSUs in lieu of cash. The RSUs provide for settlement in common shares, and therefore these RSUs are accounted for as equity awards. During the twelve months ended December 31, 2022, the Company settled 178,368 bonus RSUs, of which 82,886 were exchanged for common shares issued from treasury and 95,482 RSUs were settled at their cash value as payment for tax withholdings related to the settlement of the RSUs. In addition, during the twelve months ended December 31, 2022, 55,445 bonus deferral RSUs were granted (including RSUs in lieu of dividends) to employees of the Company pursuant to the bonus deferral RSU program. The RSUs are 100% vested.

Employee Share Purchase Plan

AQN has an Employee Share Purchase Plan (the “ESPP”) which allows eligible employees to use a portion of their earnings to purchase common shares of AQN. The aggregate number of common shares reserved for issuance from treasury by AQN under this plan shall not exceed 4,000,000 shares. During the twelve months ended December 31, 2022, the Company issued 414,338 common shares to employees under the ESPP.

As at December 31, 2022, a total of 2,357,950 common shares had been issued under the ESPP.

MANAGEMENT OF CAPITAL STRUCTURE

AQN views its capital structure in terms of its debt and equity levels at its individual operating groups and at an overall company level.

AQN’s objectives when managing capital are:

•To maintain its capital structure consistent with investment grade credit metrics appropriate to the sectors in which AQN operates;

•To maintain appropriate debt and equity levels and to limit financial constraints on the use of capital;



Algonquin Power & Utilities Corp. - Management Discussion & Analysis			45

•To ensure capital is available to finance capital expenditures sufficient to maintain existing assets;

•To ensure generation of cash is sufficient to fund sustainable dividends to shareholders as well as meet current tax and internal capital requirements;

•To maintain sufficient liquidity to pay sustainable dividends to shareholders; and

•To have appropriately sized revolving credit facilities available for ongoing investment in growth and development opportunities.

AQN monitors its cash position on a regular basis in an effort to ensure funds are available to meet current normal as well as capital and other expenditures. In addition, AQN regularly reviews its capital structure with a view to ensuring its individual business groups are using a capital structure which is appropriate for their respective industries.

RELATED PARTY TRANSACTIONS

Equity-method investments

The Company entered into a number of transactions with equity-method investees in 2022 and 2021 (see Note 16 in the annual consolidated financial statements).

The Company provides administrative and development services to its equity-method investees and is reimbursed for incurred costs. To that effect, the Company charged its equity-method investees1 $63.9 million in 2022, as compared to $25.8 million in 2021. Additionally, one of the equity-method investees (Liberty Development JV Inc.) provides development services to the Company on specified projects, for which it earns a development fee upon reaching certain milestones. During the year ended December 31, 2022, the development fees charged to the Company were $12.6 million, as compared to $2.0 million during the same periods in 2021. See Note 16 in the annual consolidated financial statements.

In 2021, a wholly-owned subsidiary of the Company made a tax equity investment into New Market Solar Investco, LLC, an equity investee of the Company and indirect owner of the New Market Solar Project. Following the closing of the construction financing facility for the New Market Solar Project, certain excess funds were distributed to the Company and in return the Company issued a promissory note of $25.8 million payable to New Market Solar Investco, LLC.

During the third quarter of 2021, the Company paid $1.5 million to Abengoa S.A. to purchase all of Abengoa S.A.'s interests in the AAGES, AAGES Development Canada Inc., and AAGES Development Spain, S.A. joint ventures. The assets acquired for AAGES Development Spain S.A included project development assets for $2.7 million and working capital of $1.5 million. The existing loan between the Company and the partnership of $3.1 million was treated as additional consideration incurred to acquire the partnership. Pursuant to an agreement between AQN and funds managed by the Infrastructure and Power strategy of Ares Management, LLC (“Ares”), in November 2021, Ares became AQN’s new partner in its non-regulated development platform for renewable energy, water and other sectors through an investment in the AAGES joint venture (subsequently renamed Liberty Development Energy Solutions B.V.) and the AAGES Development Canada Inc. joint venture (subsequently renamed Liberty Development Services Canada Inc.) which is now owned through the newly created Liberty Development JV Inc.

In 2021, the Sandy Ridge II Wind Project, the Shady Oaks II Wind Project and the New Market Solar Project were contributed into joint venture entities (in which the Company and Ares each own an indirect 50% equity interest) in exchange for loans receivable in the net amount of $10.8 million and a contract asset of $17.0 million recognized for the portion of consideration expected to be paid during the first quarter of 2023. The transfer of the New Market Solar Project resulted in a gain of $26.2 million. The transfer of the Sandy Ridge II Wind Project and the Shady Oaks II Wind Project did not result in a gain or loss.

On August 10, 2022, the Deerfield II Wind Project was contributed into a joint venture entity (in which the Company and Ares each own an indirect 50% equity interest). The transfer of the Deerfield II Wind Project did not result in a gain or loss.

Redeemable non-controlling interest held by related party

Redeemable non-controlling interest held by related party represents a preference share in a consolidated subsidiary of the Company acquired by Liberty Development Energy Solutions B.V. (see Note 17(c) in the annual consolidated financial statements). Redemption is not considered probable as at December 31, 2022. The preference share was used to finance a portion of the Company's investment in Atlantica. During the year ended December 31, 2022, the Company incurred non-controlling interest attributable to Liberty Development Energy Solutions B.V. of $15.2 million, as compared to $10.4 million during the same period in 2021, and recorded distributions of $13.8 million, for the year ended December 31, 2022 as compared to $10.2 million during the same period in 2021 (see Note 17(c) in the annual consolidated financial statements).

1 Primarily Liberty Development JV Inc. and its subsidiaries, Blue Hill Wind Energy Project Partnership, and Red Lily Wind Energy Partnership.



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Non-controlling interest held by related party

In November 2021, Ares became AQN’s new partner in its non-regulated development platform for renewable energy, water and other sectors as both parties contributed cash or assets of $19.7 million to Liberty Development JV Inc., which in turn invested $39.4 million in Algonquin (AY Holdco) B.V., a consolidated subsidiary of the Company. There was no change to the balance in 2022. The investment by Liberty Development JV Inc. is presented as a non-controlling interest held by a related party (see Note 17(c) in the annual consolidated financial statements).

Non-controlling interest held by related party represents interest in a consolidated subsidiary of the Company acquired by a subsidiary of Atlantica in May 2019 for $96.8 million. The interest was used to finance a portion of the Company's investment in the Amherst Island Wind Facility. During the year ended December 31, 2022, the Company recorded distributions of $21.0 million, as compared to $17.8 million during the same period in 2021 (see Note 17 in the annual consolidated financial statements).

The above related party transactions have been recorded at the exchange amounts agreed to by the parties to the transactions.

Transactions with Atlantica

During 2021, the Company sold Colombian solar assets to Atlantica for consideration of approximately $23.9 million, with a gain on sale of $0.9 million, and contingent consideration of approximately $2.6 million, if certain milestones were met. For the year ended December 31, 2022, a gain of $1.2 million relating to the contingent consideration has been recognized. The transaction with Atlantica is considered final with no further gains expected to be realized.

ENTERPRISE RISK MANAGEMENT

The Corporation is subject to a number of risks and uncertainties, certain of which are described below. A risk is the possibility that an event might happen in the future that could have a negative effect on the financial condition, financial performance or business of the Corporation. The actual effect of any event on the Corporation’s business could be materially different from what is anticipated or described below. The description of risks below does not include all possible risks.

Led by the Chief Compliance and Risk Officer, the Corporation has an established enterprise risk management ("ERM") framework. The Corporation’s ERM framework follows the guidance of ISO 31000 and the Committee of Sponsoring Organizations of the Treadway Commission ("COSO") Enterprise Risk Management - Integrated Framework (2013). The Corporation’s ERM Policy details the Corporation’s risk management processes and risk governance structure.

Identified risks are evaluated using a standardized risk scoring matrix to assess impact and likelihood. Financial, safety, security, reputational, reliability, and planned execution implications are among those considered when determining the impact of a potential risk. However, there can be no assurance that the Corporation's risk management activities will be successful in identifying, assessing, or mitigating the risks to which the Corporation is subject.

The risks discussed below are not intended as a complete list of all risks that AQN, its subsidiaries and affiliates are encountering or may encounter. Please see the Company's most recent AIF available on SEDAR and EDGAR for a further discussion of risk factors to which the Company is subject. To the extent of any inconsistency, the risks discussed below are intended to provide an update on those that were previously disclosed.

Risks Related to Changes in Laws and Regulations

The operations and activities of the Company, its subsidiaries and its business units are subject to the laws, regulations, orders and other requirements of a variety of federal, state, provincial and local governments, including regulatory commissions, environmental agencies and other regulatory bodies, which laws, regulations, orders and other requirements affect the operations and activities of, and costs incurred by, the Company. The Company is accordingly subject to: risks associated with changing political conditions and changes in, modifications to, or reinterpretations of, existing laws, orders or regulations, the imposition of new laws, orders or regulations (including those adopted in the State of New York allowing the North Shore Water Authority and the South Nassau Water Authority to operate in the territories of private water companies, including the power of eminent domain, and possible changes to the constitution of Chile, such as changes to the water rights rules and to provisions governing ownership of water and wastewater utilities), and the taking of other action by governmental or regulatory authorities, including, but not limited to, revocation, lapse, limitation or non-renewal of utility franchises or other rights to provide utility services to existing or new customers, potential limitations on water rights used by utilities in providing service, actions to municipalize utility service areas or limitations on utility growth and/



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or expansions of service areas, any of which could adversely affect the Company’s business, regulatory approvals, assets, results of operations and financial condition. If the Company or any of its subsidiaries or business units were found to be in violation of such applicable laws, regulations, orders or other requirements, they could be subject to significant penalties or legal actions.

Treasury Risk Management

Downgrade in the Company's Credit Rating Risk

AQN has a long term consolidated corporate credit rating of BBB from S&P, a BBB rating from DBRS and a BBB issuer rating from Fitch. APCo, the parent company for the U.S. and Canadian generating assets under the Renewable Energy Group, has a BBB issuer rating from S&P, BBB issuer rating from DBRS and a BBB issuer rating from Fitch. Liberty Utilities, the parent company for the U.S. regulated utilities under the Regulated Services Group, has a corporate credit rating of BBB from S&P and a BBB issuer rating from Fitch and a Baa2 issuer rating from Moody’s. Debt issued by Liberty GP, a special purpose financing entity of Liberty Utilities, has a rating of BBB (high) from DBRS, BBB+ from Fitch, BBB from S&P and Baa2 from Moody’s. Empire has a BBB issuer rating from S&P and a Baa1 issuer rating from Moody's. Liberty Utilities (Canada) LP, the parent company for the Canadian regulated utilities under the Regulated Services Group has an issuer rating of BBB from DBRS.

The ratings indicate the agencies’ assessment of the ability to pay the interest and principal of debt securities issued by such entities. A rating is not a recommendation to purchase, sell or hold securities and each rating should be evaluated independently of any other rating. The lower the rating, the higher the interest cost of the securities when they are sold. A downgrade in AQN’s or its subsidiaries' issuer corporate credit ratings would result in an increase in AQN’s borrowing costs under its bank credit facilities and future long-term debt securities issued. Any such downgrade could also adversely impact the market price of the outstanding securities of the Company, could impact the Company's ability to acquire additional regulated utilities and could require the Company to post additional collateral security under some of its contracts and hedging arrangements. If any of AQN’s ratings fall below investment grade (defined as BBB- or above for S&P and Fitch, BBB (low) or above for DBRS and Baa3 or above for Moody's), AQN’s ability to issue short-term debt or other securities or to market those securities would be constrained or made more difficult or expensive. Therefore, any downgrade could have a material adverse effect on AQN’s business, cost of capital, financial condition and results of operations.

The Company is not adopting or endorsing such ratings, and such ratings do not indicate AQN’s assessment of its own ability to pay the interest or principal of debt securities it issues. The Company is providing such ratings only to assist with the assessment of future risks and effects of ratings on the Company’s financing costs.

AQN is committed to maintaining its investment grade credit ratings, however no assurances can be provided that any of its current ratings will remain in effect for any given period of time or that a rating will not be lowered or withdrawn entirely by a rating agency if, in its judgment, circumstances in the future so warrant. Each rating agency employs proprietary scoring methodologies that assess business and financial risks of the entity rated. There can be no assurance that the principles on which the rating is based remain consistently applied, and these principles are subject to change from time to time at each rating agency’s discretion. For example, a rating agency’s views on total allowable leverage, specific industry risk factors, country risk and the company’s business mix, among other factors, may change. Such changes could require AQN to adjust its business and strategy in order to maintain its credit ratings. AQN currently anticipates that to continue to maintain a BBB flat investment grade credit rating, it will, among other things, need to execute its growth and asset recycling strategies in a manner that preserves financial leverage targets and continues to generate at least 70% of EBITDA (as determined by applicable rating agency methodologies) from AQN’s Regulated Services Group. There can be no assurance that AQN will be successful, and the failure to do so could have a negative impact on AQN’s credit ratings. The business mix target may from time to time require AQN to grow its Regulated Services Group or implement other strategies in order to pursue investment opportunities within the Renewable Energy Group.

Capital Markets and Liquidity Risk

As at December 31, 2022, the Company had approximately $7,512.3 million of long-term consolidated indebtedness. Management of the Company believes, based on its current expectations as to the Company's future performance, that the cash flow from operations, the funds available under its credit facilities and from future asset recycling initiatives, and its ability to access capital markets will be adequate to enable the Company to finance its operations, execute its business strategy and maintain an adequate level of liquidity. However, the Company's expected revenue and capital expenditures are only estimates. Moreover, actual cash flows from operations will depend on regulatory, market and other conditions that are beyond the Company's control and which may be impacted by the risk factors herein. As a result, there can be no assurance that management’s expectations as to future performance will be realized.

The Company's ability to obtain additional debt or equity or issue other securities, on favourable terms or at all, may be adversely affected by negative perceptions of the Company, any adverse financial or operational performance, financial market disruptions, the failure or collapse of any financial institution, prevailing market views or perceptions, or other



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factors outside the Company's control. In addition, the Company may at times incur indebtedness in excess of its long-term leverage targets, in advance of raising the additional equity or similar securities or executing on asset recycling strategies necessary to repay such indebtedness and maintain its long-term leverage target. Any increase in the Company’s leverage or degradation of key credit metrics below threshold levels could, among other things: limit the Company’s ability to obtain additional financing for working capital, investment in subsidiaries, capital expenditures, debt service requirements, acquisitions and general corporate or other purposes; restrict the Company’s flexibility and discretion to operate its business; limit the Company’s ability to declare dividends; require the Company to dedicate a portion of cash flows from operations to the payment of interest on its existing indebtedness, in which case such cash flows would not be available for other purposes; cause rating agencies to re-evaluate or downgrade the Company’s existing credit ratings; require the Company to post additional collateral security under some of its contracts and hedging arrangements; expose the Company to increased interest expense on borrowings at variable rates; limit the Company’s ability to adjust to changing market conditions; place the Company at a competitive disadvantage compared to its competitors; make the Company vulnerable to any downturn in general economic conditions; render the Company unable to make expenditures that are important to its future growth strategies and require the Company to pursue alternative funding strategies, which may include accelerated asset recycling initiatives.

The Company will need to refinance or reimburse amounts outstanding under the Company’s existing consolidated indebtedness over time. There can be no assurance the Company will be successful in refinancing its indebtedness when necessary or that additional financing will be obtained when needed, on commercially reasonable terms or at all. In the event that the Company cannot refinance its indebtedness or raise additional indebtedness on terms that are not less favourable than the current terms, the Company's cash flows, ability to declare dividends or repay its indebtedness may be adversely affected.

The Company's ability to meet its debt service requirements will depend on its ability to generate cash in the future, which depends on many factors, including the Company's financial performance, debt service obligations, the realization of the anticipated benefits of acquisition and investment activities, and working capital and capital expenditure requirements. In addition, the Company's ability to borrow funds in the future to make payments on outstanding debt will depend on the satisfaction of covenants in existing credit agreements and other agreements. A failure to comply with any covenants or obligations under the Company’s consolidated indebtedness could result in a default under one or more such instruments, which, if not cured or waived, could result in the termination of dividends by the Company and permit acceleration of the relevant indebtedness. There can be no assurance that, if such indebtedness were to be accelerated, the Company's assets would be sufficient to repay such indebtedness in full. There can also be no assurance that the Company will generate cash flow in amounts sufficient to pay its outstanding indebtedness or to fund the Company's liquidity needs.

Interest Rate Risk

The Company is exposed to interest rate risk due to the impact of increasing benchmark interest rates and credit spreads on certain outstanding variable interest indebtedness, as well as any new borrowings on existing and new credit facilities and other debt issuances. Fluctuations in interest rates may also impact the costs to obtain other forms of capital and the feasibility of planned growth initiatives.

In addition, for the Regulated Services Group, costs resulting from interest rate increases may not be recoverable in whole or in part, and “regulatory lag” may cause a time delay in the payment to the Regulated Services Group of any such costs that are recoverable. Rising interest rates may also negatively impact the economics of development projects, acquisitions and energy facilities, especially where project financing is being renewed or arranged.

The Company's financing of its capital expenditures, including the Kentucky Power Transaction, is also exposed to changes in benchmark interest rates and credit spreads. While the Company intends to use the net proceeds from its approximately C$800 million common share offering that closed on November 8, 2021 (the "2021 Bought Deal Offering") and the Note Offerings to finance the Kentucky Power Transaction, all such net proceeds have, in the short term, been used to repay variable rate indebtedness under credit facilities of the Company and certain of its subsidiaries prior to closing of the Kentucky Power Transaction. As a result, the Company expects to draw from the credit facilities of the Company and certain of its subsidiaries in connection with the closing of the Kentucky Power Transaction. Given the rise in variable rates experienced in 2022 and to date in 2023, together with potential future interest rate increases, the Company expects higher financing costs for the Kentucky Power Transaction and other pending capital investments than initially anticipated.

As a result, fluctuations in interest rates, including the rate increases experienced in 2022, could materially increase the Corporation’s financing costs, limit the Corporation’s options for financing, and adversely affect its results of operations, cash flows, key credit metrics, borrowing capacity and ability to implement its business strategy.

As at December 31, 2022, approximately 89% of debt outstanding in AQN and its subsidiaries was subject to a fixed rate of interest and as a result, such debt is not subject to significant interest rate risk in the short term time horizon.

Borrowings subject to variable interest rates can fluctuate significantly from month to month, quarter to quarter and year to year. AQN's target is to maintain a minimum of 85% fixed rate debt. As a result, the Company hedges the interest rate risk



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on its variable interest rate borrowings from time to time. On December 17, 2022, the Company entered into an interest rate cap agreement in the amount of $390 million for the period between January 15, 2023 and January 15, 2024.

Based on amounts outstanding as at December 31, 2022, the impact to interest expense on variable rate loans from changes in interest rates are as follows:

•the Corporate Credit Facility is subject to a variable interest rate and had $180.1 million outstanding as at December 31, 2022. As a result, a 100 basis point change in the variable rate charged would impact interest expense by $1.8 million annually;

•the Long Term Regulated Services Credit Facility is subject to a variable interest rate and had no amounts outstanding as at December 31, 2022. As a result, a 100 basis point change in the variable rate charged would not impact interest expense;

•the Short Term Regulated Services Credit Facility is subject to a variable interest rate and had no amounts outstanding as at December 31, 2022. As a result, a 100 basis point change in the variable rate charged would not impact interest expense;

•the Regulated Services Delayed Draw Term Facility is subject to a variable interest rate and had $610.4 million outstanding as at December 31, 2022. The Regulated Services Group has locked in the variable rate until May 31, 2023 through an interest election request. As a result, a 100 basis point change in the variable rate charged would impact interest expense by $3.1 million until the maturity date of November 29, 2023;

•the Bermuda Credit Facility is subject to a variable interest rate and had $74.3 million outstanding as at December 31, 2022. As a result, a 100 basis point change in the variable rate charged would impact interest expense by $0.7 million annually;

•the Bermuda Working Capital Facility is subject to a variable interest rate and had $20.0 million outstanding as at December 31, 2022. As a result, a 100 basis point change in the variable rate charged would impact interest expense by $0.2 million annually;

•the Regulated Services Group's commercial paper program is subject to a variable interest rate and had $407.0 million outstanding as at December 31, 2022. As a result, a 100 basis point change in the variable rate charged would impact interest expense by $4.1 million annually;

•the Renewable Energy Credit Facility is subject to a variable interest rate and had $77.4 million outstanding as at December 31, 2022. As a result, a 100 basis point change in the variable rate charged would impact interest expense by $0.8 million annually;

•term facilities at ESSAL that are subject to variable interest rates had $93.1 million outstanding as at December 31, 2022. As a result, a 100 basis point change in the variable rate charged would impact interest expense by $0.9 million annually; and

Term facilities at BELCO are not subject to variable interest rates as the Company entered into the above noted interest swap agreements to hedge the risk associated with interest rate fluctuation. In addition, on January 13, 2022, the Company entered into a forward starting swap to fix the interest rate for the second five-year term of the U.S. Notes.

Foreign Currency Risk

The functional currency of most of AQN's operations is the U.S. dollar, however AQN is exposed to currency fluctuations from its Canadian and Chilean operations and may utilize equipment and/or commodities purchased from foreign suppliers.

AQN may enter into derivative contracts to hedge all or a portion of currency exchange rate exposure that is transactional in nature and where a natural economic hedge does not exist (see Note 24 (b)(iii) in the annual consolidated financial statements). To the extent that the Company does enter into currency hedges, the Company may not realize the full benefits of favourable exchange rate movement, and is subject to risks that the counterparty to the hedging contracts may prove unable or unwilling to perform their obligations under the contracts.

Canadian operations

The Company is exposed to currency fluctuations from its Canadian-based operations. AQN manages this risk primarily through the use of natural hedges by using long-term debt in Canadian Dollars to finance its Canadian operations and a combination of foreign exchange forward contracts and spot purchases.

Chilean operations

The Company is exposed to currency fluctuations from its Chilean-based operations. AQN manages this risk primarily through the use of natural hedges by using long-term debt in Chilean pesos or indexed to the Chilean Peso to finance its Chilean operations.



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Tax Risk and Uncertainty

The Corporation is subject to income and other taxes primarily in the United States and Canada; however, it is also subject to income and other taxes in international jurisdictions, such as Chile and Bermuda. Changes in tax laws or interpretations thereof in the jurisdictions in which the Corporation does business could adversely affect the Company's results from operations, returns to shareholders, and cash flows. One or more taxing jurisdictions could seek to impose incremental or new taxes on the Company pursuant to one of the following or otherwise:

•The Inflation Reduction Act was signed into law in the United States on August 16, 2022. The legislation is inclusive of an extension and expansion of clean energy tax credits and a minimum tax. The minimum tax is not expected to be applicable to the Company in the near term; however, the Company cannot provide any assurance that it will not apply in the longer term.

•As a consequence of the Organization for Economic Co-operation and Development’s (“OECD”) various initiatives on “Base Erosion and Profit Shifting”, there has been increased focus by taxing authorities across the globe to pursue common international principles for the entitlement to taxation of global corporate profits and eliminate perceived tax advantages enjoyed by multinational enterprises. Certain components of the relevant legislation in the jurisdictions in which the Corporation operates or has domiciled subsidiaries are expected to apply with application expected no earlier than January 1, 2023. As the local legislation in the various jurisdictions is enacted and comes into effect, there is a risk that the Company's tax expense and/or cash taxes could materially increase or that the Company's interpretation of the new legislation may not align with that of the relevant tax authority’s interpretation. This could have a material adverse effect on the Corporation’s financial condition, results of operations, and cash flows in future periods.

Credit/Counterparty Risk

AQN and its subsidiaries are subject to credit risk with respect to the ability of customers and other counterparties to perform their obligations to the Company, including paying amounts that they owe to AQN or its subsidiaries. This credit risk exists with respect to utility customers, banks and other financing sources, as well as counterparties to long term PPAs, trade receivables, derivative financial instruments, energy management agreements, Engineering, Procurement, and Construction contracts, manufacturer contracts, and natural gas supply agreements, among others. Additionally, bank deposits in excess of deposit insurance limits are subject to the risk that such excess amounts could be lost or forfeited in the event of a bank failure.

The Renewable Energy Group's revenues are approximately 13% of total Company revenues with the majority earned from large utility customers having a credit rating of Baa2 or better by Moody's, or BBB or higher by S&P, or BBB or higher by DBRS.

The remaining revenue of the Company is primarily earned by the Regulated Services Group.



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The credit risk attributed to the Regulated Services Group's accounts receivable balances at the water and wastewater distribution systems total $86.0 million which is spread over approximately 560,000 customer connections, resulting in an average outstanding balance of approximately $150 dollars per customer connection.

The natural gas distribution systems accounts receivable balances related to the natural gas utilities total $167.4 million, while electric distribution systems accounts receivable balances related to the electric utilities total $165.0 million. The natural gas and electrical utilities both derive over 85% of their revenue from residential customers and have a per customer connection average outstanding balance of $446 dollars and $534 dollars respectively. Counterparty performance risk also exists in the natural gas distribution where suppliers could potentially fail to supply natural gas leading to disruptions and potentially higher procurement costs. These risks are mitigated through the receipt of collateral from counterparties.

Adverse conditions in the energy industry or in the general economy, including the effects of the COVID-19 pandemic, as well as circumstances of individual customers or counterparties, may adversely affect the ability of a customer or counterparty to perform as required under its contract with the Company. Losses from a utility customer may not be offset by bad debt reserves approved by the applicable utility regulator. If a customer under a PPA, unit contingent or fixed-shape offtake contract or other energy offtake or hedging arrangement with the Company is unable to perform, the Renewable Energy Group may be unable to replace the contract on comparable terms, in which case sales of power (and, if applicable, RECs and ancillary services) from the facility would be subject to market price risk and may require refinancing of indebtedness related to the facility or otherwise have a material adverse effect. Default by other counterparties, including lenders and counterparties to supply and construction contracts, hedging contracts that are in an asset position, short-term investments, agreements for the purchase of goods or services or other agreements, also could adversely affect the financial results of the Corporation.

Market Price Risk

The Renewable Energy Group assets subject to long term PPAs are not exposed to market risk for this portion of its portfolio. Where a generating asset is not covered by a PPA, the Renewable Energy Group may seek to mitigate market risk exposure by entering into financial or physical power hedges requiring that a specified amount of power be delivered at a specified time in return for a fixed price. There is a risk that there is a difference between the pricing at the location where power is delivered and where the hedge settles, known as basis risk, which may result in reduced net revenue and earnings volatility for the Company. Basis risk can exist even where the energy output from a facility is contracted. In an effort to mitigate basis risk, the Company seeks to enter into additional financial contracts in order to fix the price of basis on a portion of the production from specific assets. There is a risk that the Company is not able to generate the specified amount of power at the specified time resulting in production shortfalls under the hedge that then requires the Company to purchase power in the merchant market. To mitigate the risk of production shortfalls under hedges, the Renewable Energy Group generally seeks to structure hedges to cover less than 100% of the anticipated production, thereby reducing the risk of not producing the minimum hedge quantities. Nevertheless, due to unpredictability in the natural resource or due to grid curtailments or mechanical failures, production shortfalls may be such that the Renewable Energy Group may still be forced to purchase power in the merchant market at prevailing rates to settle against a hedge. Any event that restricts production increases shortfall risk. Events that can reduce production include (but are not limited to) weather events (such as icing, low wind resource, cloud cover), transmission outages and mechanical failure. The Corporation is subject to the risk of impairment to its renewable power generation assets associated with potential declines in long term forecasted power prices for the period following the expiration of PPAs, unit contingent or fixed-shape offtake contracts or other energy offtake or hedging arrangements, as well as the expiration or decline in value of RECs and other sources of revenue.

Hedges currently put in place by the Renewable Energy Group for its operating facilities along with residual exposures to the market are detailed below:

The Senate, Sandy Ridge and Minonk Wind Facilities have entered into financial hedges that end between 2027 and 2028. The financial hedges are structured to hedge an average of approximately 65% of annual LTAR against exposure to the applicable hub current spot market rates. The average unhedged production based on LTAR is approximately 488 GW-hrs annually.

The Sugar Creek Wind Facility has a financial hedge in place until the end of 2030 which is structured to hedge an average of 73% of annual LTAR against exposure to the applicable hub current spot market rates. The average unhedged production based on LTAR is approximately 200 GW-hrs annually.

The Maverick Creek Wind Facility has unit contingent PPAs until the end of 2031 which are structured to hedge an average of 76% of annual LTAR against exposure to the applicable hub current spot market rates. The annual average unhedged production based on LTAR is approximately 466 GW-hrs annually.

Under each of the above noted hedges, if production is not sufficient to meet the unit quantities under the hedge, the shortfall must be purchased in the open market at market rates. The effect of this risk exposure could be material. The



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Renewable Energy Group tries to manage this risk by forecasting shortfalls and entering into offsetting transactions (buy back). However, the existence and extent of any shortfall cannot always be predicted.

In addition to the above noted hedges, from time to time the Renewable Energy Group enters into short-term derivative contracts (usually with terms of one to three months) to further mitigate market price risk exposure due to production variability. As at December 31, 2022, the Renewable Energy Group had entered into hedges with a cumulative notional quantity of 16,140 GW-hrs.

The Company has elected the fair value option under ASC 825, Financial Instruments to account for its investment in Atlantica, with changes in fair value reflected in the annual consolidated statement of operations. As a result, each dollar change in the traded price of Atlantica shares will correspondingly affect the Company's net earnings by approximately $44 million.

Commodity Price Risk

The Regulated Services Group is exposed to energy and natural gas price risks at its electric and natural gas systems. The Renewable Energy Group's exposure to commodity prices is primarily limited to exposure to natural gas price risk. In this regard, a representative discussion of these risks is set out as follows:

Regulated Services Group

The CalPeco Electric System provides electric service to the Lake Tahoe California basin and surrounding areas at rates approved by the CPUC. The CalPeco Electric System purchases the energy, capacity, and related service requirements for its customers from NV Energy via a PPA at rates reflecting NV Energy’s system average costs.

The CalPeco Electric System's tariffs allow for the pass-through of energy costs to its rate payers on a dollar for dollar basis, through the Energy Cost Adjustment Clause ("ECAC") mechanism, which allows for the recovery or refund of changes in energy costs that are caused by the fluctuations in the price of fuel and purchased power. On a monthly basis, energy costs are compared to the CPUC approved base tariff energy rates and the difference is deferred to a balancing account. Annually, based on the balance of the ECAC balancing account, if the ECAC revenues were to increase or decrease by more than 5%, the CalPeco Electric System's ECAC tariff allows for a potential adjustment to the ECAC rates which would eliminate the risk associated with the fluctuating cost of fuel and purchased power.

The Granite State Electric System is an open access electric utility allowing for its customers to procure commodity services from competitive energy suppliers. For those customers that do not choose their own competitive energy supplier, Granite State Electric System provides a Default Service offering to each class of customers through a competitive bidding process. This process is undertaken semi-annually for all Default Service customers. The winning bidder is obligated to provide a full requirements service based on the actual needs of the Granite State Electric System’s Default Service customers. Since this is a full requirements service, the winning bidder(s) take on the risk associated with fluctuating customer usage and commodity prices. The supplier is paid for the commodity by the Granite State Electric System which in turn receives pass-through rate recovery through a formal filing and approval process with the NHPUC on a semi-annual basis. The Granite State Electric System is only committed to the winning Default Service supplier(s) after approval by the NHPUC so that there is no risk of commodity commitment without pass-through rate recovery.

The EnergyNorth Natural Gas System purchase pipeline capacity, storage and commodity from a variety of counterparties. The EnergyNorth Natural Gas System's portfolio of assets and its planning and forecasting methodology are commonly approved periodically by the NHPUC through Least Cost Integrated Resource Plan filings which typically are filed bi-annually but can be as long as a five-year interim period depending on the length of the review process. In addition, EnergyNorth Natural Gas System files with the NHPUC for recovery of its transportation and commodity costs on an annual basis through the Cost of Gas ("COG") filing and approval process. The EnergyNorth Natural Gas System establishes rates for its customers based on the NHPUC's approval of its filed COG. These rates are designed to fully recover its anticipated transportation and commodity costs. In order to minimize commodity price fluctuations, the EnergyNorth Natural Gas System locks in a fixed price basis for approximately 16% of its normal winter period purchases under a NHPUC approved hedging program. All costs associated with the fixed basis hedging program are allowed to be a pass-through to customers through the COG filing and the approved rates in said filing. Should commodity prices increase or decrease relative to the initial annual COG rate filing, the EnergyNorth Natural Gas System has the right to automatically adjust its COG rates going forward up to 25% in order to minimize any under or over collection of its natural gas costs. In addition, any under collections may be carried forward with interest to the next year’s corresponding COG period (i.e. winter to winter and summer to summer).

The Midstates Gas and Empire Gas Systems purchases pipeline capacity, storage and commodity from a variety of counterparties, and file with the individual state commissions for recovery of their respective transportation and commodity costs through an annual Purchase Gas Adjustment (“PGA”) filing and approval process. The Midstates Gas Systems serves customers in Missouri, Illinois and Iowa and establishes rates for its customers within the PGA filing in each state and these rates are designed to fully recover its anticipated transportation, storage and commodity costs. In order to minimize commodity price fluctuations, the Midstates Gas System has implemented a commodity hedging program, consistent with



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regulator expectations and approvals, designed to hedge approximately 25-50% of its non-storage related commodity purchases. All gains and losses associated with the hedging program are allowed to be a pass-through to customers through the PGA filing and are embedded in the approved rates in said filing. Rates can be adjusted on a monthly or quarterly basis in order to account for any commodity price increase or decrease relative to the initial PGA rate, minimizing any under or over collection of its natural gas costs. Similar to the Midstates Gas System, the Empire Gas System serves customers in Missouri, and also implements a commodity hedging program designed to hedge 70% to 90% of its winter demand inclusive of storage volumes withdrawn during the winter period. All related costs are embedded in approved rates and allowed to be a pass through to customers in the PGA. The Empire Gas System is permitted to file an Actual Cost Adjustment (“ACA”) once a year which also includes a PGA filing. In addition to the ACA filing, three more optional PGA filings are allowed during the year. The Empire Gas System’s ACA year is from September 1 to August 31 for each year.

The Peach State Gas System purchases pipeline capacity, storage and commodity from a variety of counterparties, and files with the Georgia Public Service Commission ("PSC") for recovery of its transportation, storage and commodity costs through a monthly PGA filing process. The Peach State Gas System establishes rates for its customers within the PGA filings and these rates are designed to fully recover its anticipated transportation, storage and commodity costs. In order to minimize commodity price fluctuations, the annual Gas Supply Plan filed by the Company and approved by the Georgia PSC includes a commodity hedging program designed to hedge approximately 30% of its non-storage related commodity purchases during the winter months. All gains and losses associated with the hedging program are passed through to customers in the PGA filings and are embedded in the approved rates in such filings. Rates can be adjusted on a monthly basis in order to account for any differences in natural gas costs relative to the amounts assumed in the PGA filings, minimizing any under or over collection of its natural gas costs.

The Empire Electric System’s natural gas procurement program for electrical generation is designed to manage costs to mitigate volatile natural gas prices. The Empire Electric System periodically enters into fixed price contracts with counterparties to hedge future natural gas prices in an attempt to lessen the volatility in fuel expenditures. Generally, the over/under variances associated with the hedging program are passed through to customers in the fuel adjustment clause assuming they are deemed to be prudently incurred.

BELCO purchases Heavy Fuel Oil, Light Fuel Oil and diesel which are transported and stored in facilities in Bermuda until such time as they are delivered and consumed in its electricity generation operations. While the cost of this fuel is included in traditional rate filings through a Fuel Adjustment Rate (“FAR”), the variability in the commodity pricing has led the Regulatory Authority of Bermuda to establish a quarterly reconciliation and adjustment to the FAR. This filing evaluates current commodity pricing and usage as well as projected commodity pricing to develop the FAR for the upcoming quarter. Additionally, BELCO has periodically used hedging to lock in commodity rates in an effort to reduce pricing volatility and protect customer rates.

Renewable Energy Group

The Sanger Thermal Facility’s offtake agreement includes provisions which reduce its exposure to natural gas price risk. In this regard, a $1.00 increase in the price of natural gas per MMBTU, based on expected production levels, would result in a decrease in net revenue by approximately $1.36 million on an annual basis.

The Windsor Locks Thermal Facility’s offtake agreement includes provisions which reduce its exposure to natural gas price risk but has exposure to market rate conditions for sales above those to its primary customer. In this regard, a $1.00 increase in the price of natural gas per MMBTU, based on expected production levels, would result in a decrease in net revenue by approximately $0.50 million on an annual basis.

The Maritime region provides short-term energy requirements to various customers at fixed rates. The energy requirements of these customers are estimated at approximately 70,000 MW-hrs in fiscal 2023, of which 70,000 MW-hrs is presently contracted. The Tinker Hydro Facility is expected to provide the vast majority of the energy required to service these customers and the Maritime region anticipates having to purchase a minimal amount of its energy requirements at the ISO-NE spot rates to supplement self-generated energy to manage potential hourly imbalances between load requirements and generation.

OPERATIONAL RISK MANAGEMENT

Mechanical and Operational Risks

AQN's profitability could be impacted by, among other things, equipment failure, the failure of a major customer to fulfill its contractual obligations, reductions in average energy prices, a strike or lock-out at a facility, natural disasters, diseases (including COVID-19) and other force majeure events, interruption in supply chain and expenses related to claims or clean-up to adhere to environmental and safety standards.

The Regulated Services Group's water and wastewater distribution systems operate under pressurized conditions within pressure ranges approved by regulators. Should a water distribution network become compromised or damaged, the resulting release of pressure could result in serious injury or death to individuals or damage to other property. In addition,



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water contamination a in drinking water distribution system could result in severe illness or death to those who drink the contaminated water.

The Regulated Services Group's electric distribution systems are subject to storm events, usually winter storm events, whereby power lines can be brought down, with the attendant risk to individuals and property. Wildfires may occur within the Regulated Services Group’s electric distribution service territories, including, without limitation, in California and the southern United States, such as the Mountain View fire that occurred on November 17, 2020, within the CalPeco Electric System’s service territory in California. In forested areas, trees falling on and lightning strikes to, distribution lines or equipment, can ignite wildfires which may pose a risk to life and property. If the Company is accused or found to be responsible for such a fire, the Company could suffer costs, losses and damages, including inverse condemnation, all or some of which may not be recoverable through insurance, legal, regulatory recovery and other processes.

The Regulated Services Group's natural gas distribution systems are subject to risks which may lead to fire and/or explosion which may impact life and property. Risks include third party damage, compromised system integrity, type/age of pipelines, and severe weather events.

The Company's hydro assets utilize dams to pond water for generation and if the dams fail/breach potentially catastrophic amounts of water would flood downriver from the facility. The dams can be subjected to drought conditions and lose the ability to generate during peak load conditions, causing the facilities to fall short of either hedged or PPA committed production levels. The risks of the hydro facilities are mitigated by regular dam inspections and a maintenance program of the facility to lessen the risk of dam failure.

The Company's assets could catch on fire and, depending on the season, could ignite significant amounts of forest or crop downwind from the wind farms. The wind units could also be affected by large atmospheric conditions, which could lower wind levels below the Company's PPA and hedge minimum production levels. The wind units can experience failures in the turbine blades or in the supporting towers. Production risks associated with the wind turbine generators failures is mitigated by properly maintaining the units, using long term maintenance agreements with the turbine O&Ms which provide for regular inspections and maintenance of property, and liability insurance policies.

The Company's Thermal Energy Division uses natural gas and oil, and produces exhaust gases, which if not properly treated and monitored could cause hazardous chemicals to be released into the atmosphere. The units could also be restricted from purchasing natural gas/oil due to either shortages or pollution levels, which could hamper output of the facility. The mechanical and operational risks at the thermal facilities are mitigated through the regular maintenance of the boiler system, and by continual monitoring of exhaust gases. Fuel restrictions can be hedged in part by long term purchases.

All of the Renewable Energy Group's electric generating stations are subject to mechanical breakdown. The risk of mechanical breakdown is mitigated by properly maintaining the units and by regular inspections.

In general, these risks are, in part, mitigated through the diversification of AQN’s operations, both operationally and geographically. In addition, AQN seeks to mitigate these risks through the use of regular maintenance programs, including pipeline safety programs and compliance programs, the provision of adequate insurance, an active Enterprise Risk Management program and the establishment of reserves for expenses.

Regulatory Risk

Profitability of AQN businesses is, in part, dependent on regulatory climates in the jurisdictions in which those businesses operate. In the case of some of Renewable Energy Group's hydroelectric facilities, water rights are generally owned by governments that reserve the right to control water levels, which may affect revenue.

The Regulated Services Group’s facilities are subject to rate setting by its regulatory agencies. The Regulated Services Group operates in 13 U.S. states, one Canadian province, Bermuda and Chile and therefore is subject to regulation from 17 different regulatory agencies including FERC. The time between the incurrence of costs and the granting of the rates to recover those costs by regulatory agencies is known as regulatory lag. As a result of regulatory lag, inflationary effects and timing delays may impact the ability to recover expenses and/or capital costs, and profitability could be impacted. In order to mitigate this exposure, the Regulated Services Group seeks to obtain approval for regulatory constructs in the states in which it operates to allow for timely recovery of operating expenses and capital costs. A fundamental risk faced by any regulated utility is the disallowance of operating expenses or capital costs to be placed into its revenue requirement by the utility's regulator. In addition, capital investments that have become stranded may pose additional risk for cost recovery and could be subject to legislative proposals that would impact the extent to which such costs could be recovered. To the extent proposed costs are not included in the utility's revenue requirement, the utility will be required to find other efficiencies, growth opportunities or cost savings to achieve its allowed returns.

The Regulated Services Group regularly works with its governing authorities to manage the affairs of the business, employing local, state level, and corporate resources.



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Condemnation Expropriation Proceedings

The Regulated Services Group's distribution systems could be subject to condemnation or other methods of taking by government entities under certain conditions. Any taking by government entities would legally require fair compensation to be paid. Determination of such fair compensation is undertaken pursuant to a legal proceeding and, therefore, there is no assurance that the value received for assets taken will be in excess of book value.

Inflation Risk

AQN's profitability could be impacted by inflation increases above long-term averages. The Regulated Services Group’s facilities are subject to rate setting by its regulatory agencies. The time between the incurrence of costs and the granting of the rates to recover those costs by regulatory agencies is known as regulatory lag. As a result of regulatory lag, inflationary effects and timing delays may impact the ability to recover expenses and/or capital costs, and profitability could be impacted. In the event of significant inflation, the impact of regulatory lag on the Company would be increased. In order to mitigate this exposure, the Regulated Services Group seeks to obtain approval for regulatory constructs in the states in which it operates to allow for timely recovery of operating expenses and capital costs.

The Renewable Energy Group's assets are subject to long term PPAs, most of which are not indexed to inflation and could experience declines in profitability if operating costs increase at a rate greater than the offtake price.

Development and construction projects could experience a decrease in expected returns as a result of increased costs. To mitigate the risk of inflation the Company attempts to enter into fixed price construction agreements and fixed price offtake agreements.

Tariff Risk

Changes in tariffs or duties, such as antidumping and countervailing duty rates that could be put in place as a result of the U.S. Department of Commerce's investigation into an antidumping and countervailing duties circumvention claim on solar cells and panels supplied from Malaysia, Vietnam, Thailand and Cambodia, may adversely affect the capital expenditures required to develop or construct the Corporation’s projects, as well as the timing for completion, or viability, of such projects. In the U.S., tariffs have been imposed in recent years on imports of solar panels, aluminum and steel, among other goods and raw materials. These occurrences may have adverse impacts to the Corporation, as the buyer of goods, which could adversely affect the Corporation’s expected returns, results of operations and cash flows.

Risks Relating to the Kentucky Power Transaction

The closing of the Kentucky Power Transaction is subject to the normal commercial risks that such acquisition will not close on the terms negotiated or at all. The Kentucky Power Transaction remains subject to closing conditions, including the approval of FERC and clearance pursuant to the Hart-Scott-Rodino Antitrust Improvements Act of 1976 (as the clearance received previously has lapsed). The failure to satisfy or waive the conditions may result in the termination of the Kentucky Acquisition Agreement. Accordingly, there can be no assurance that the Company will complete the Kentucky Power Transaction on the basis described herein, if at all. As the Kentucky Power Transaction is subject to various regulatory approvals, it is consequently subject to the risks that such approvals may not be timely obtained or may impose unfavourable conditions that could impair the ability to complete the acquisition or impose adverse conditions on the Company in order to complete the acquisition. The presence of intervenors in the regulatory approval process has the effect of increasing these risks.

If the Kentucky Power Transaction is not completed, the Company could be subject to a number of risks that may adversely affect the Company’s business, financial condition, results of operations, reputation and cash flows, including (i) the requirement to pay costs relating to the Kentucky Power Transaction, including costs relating to the financing thereof and obtaining regulatory approval and (ii) time and resources committed by the Company’s management to matters relating to the Kentucky Power Transaction that could otherwise have been devoted to pursuing other beneficial opportunities. In addition, if the Kentucky Acquisition Agreement for the Kentucky Power Transaction is terminated in certain circumstances, the Company may be required to pay a termination fee of $65 million.

Business combinations such as the Kentucky Power Transaction involve risks that could materially and adversely affect the Company’s business plan, including the failure to realize the results that the Company expects. Transition and integration activities associated with this business combination may not go as planned, creating the potential for increased costs, service disruption, noncompliance, reputational harm and other negative outcomes. There can be no assurance that the Company will be successful in increasing the historical returns earned by either Kentucky Power or Kentucky Transco, that the load declines experienced by Kentucky Power over recent years will not continue to be a prevailing trend, or that the Company will be able to fully realize some or all of the expected benefits of the Kentucky Power Transaction or succeed in implementing its strategic objectives relating to the acquired entities, including the success of the transfer of operational control of the Mitchell Plant from Kentucky Power to the Wheeling Power Company and the transition of Kentucky Power’s generating mix to greener sources (i.e. “greening the fleet” initiatives). The ability to realize these anticipated benefits and implement these strategic objectives will depend in part on successfully retaining staff, hiring additional staff to replace



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certain of the sellers’ centralized operations, obtaining favourable regulatory outcomes, realizing growth opportunities, no unanticipated economic changes in the areas where the acquired entities operate, and potential synergies through the coordination of activities and operations with the Company’s existing business. There is a risk that some or all of the expected benefits and strategic objectives will fail to materialize, or may not occur within the time periods anticipated by the Company. A failure to realize the anticipated benefits of or implement strategic objectives relating to the Kentucky Power Transaction on an efficient and effective basis could have a material adverse effect on the Company’s financial condition, results of operations, reputation and cash flows.

A change in the capital structure of the Company could cause credit rating agencies which rate the Company’s outstanding debt obligations to re-evaluate and potentially downgrade the Company’s current credit ratings, which could increase the Company’s borrowing costs and adversely impact the market price of the outstanding securities of the Company.

The Kentucky Power Transaction could also result in a downgrade of the credit rating of Kentucky Power or its outstanding bonds, and could require Kentucky Power to offer to prepay $525 million in principal amount of its outstanding bonds if the credit ratings thereof fall below investment grade (or in the event such bonds are placed on “credit watch” or assigned a “negative outlook” if they are rated BBB- by S&P or Baa3 by Moody’s at such time).

There may be liabilities that the Company failed to discover or was unable to quantify in the Company’s due diligence, and the Company may not have recourse for some or all of these potential liabilities. While the Company has accounted for these potential liabilities for the purposes of making its decision to enter into the Kentucky Acquisition Agreement, there can be no assurance that any such liability will not exceed the Company’s estimates. In connection with the Kentucky Power Transaction, the Company has obtained a representation and warranty insurance policy, with coverage up to $255 million, subject to an initial retention of $21 million. Nevertheless, this insurance policy is subject to certain exclusions and limitations and there may be circumstances for which the insurer attempts to limit such coverage or refuses to indemnify the Company or where the coverage provided under the insurance policy may otherwise be insufficient or inapplicable.

Kentucky Power and Kentucky Transco are party to agreements that contain change of control and/or termination for convenience provisions which may be triggered following completion of the Kentucky Power Transaction. The operation of these change of control or termination provisions, if triggered, could result in unanticipated expenses and/or cash payments following the consummation of the Kentucky Power Transaction or adversely affect the acquired entities’ results of operations and financial condition. Unless these change of control provisions are waived, or the termination provisions are not exercised, by the other party, the operation of any of these provisions could adversely affect the results of operations and financial condition of the Company and the acquired entities.

Although a portion of the Company's electricity is produced by the combustion of fossil fuels, all of the electricity generated by Kentucky Power is produced by the combustion of fossil fuels. As a result, the acquisition of Kentucky Power would increase the overall percentage of the Company's electricity generation that is produced by the combustion of fossil fuels and could result in reputational harm to the Company and adversely affect perceptions regarding the Company’s commitment to environmental and sustainability matters, as well as the Company’s ability to accomplish its environmental and sustainability objectives. The operation of fossil-fueled generation plants, including resulting emissions of nitrogen and sulfur oxides, mercury and particulates and the discharge and disposal of solid waste (including coal-combustion residuals (“CCRs”)), is subject to extensive federal, state and local environmental statutes, rules and regulations relating to air quality, water quality, waste management, natural resources and health and safety. Compliance with these requirements requires Kentucky Power to incur significant costs, including capital expenditures, for environmental monitoring, installation of pollution control equipment, emission fees, disposal activities, decommissioning, and permitting obligations. If these compliance costs become uneconomical, Kentucky Power may ultimately be required to retire generating capacity prior to the end of its estimated life. The costs of complying with these legal requirements could also adversely affect Kentucky Power’s results of operations, financial condition and cash flows, and those of the Company following the closing of the Kentucky Power Transaction. In addition, the impacts could become even more significant if existing requirements governing air emissions management and disposal, CCR waste and/or waste matter discharge become more restrictive in the future, more extensive operating and/or permitting requirements are imposed or additional substances associated with power generation are subjected to increased regulation. Although Kentucky Power typically recovers expenditures for pollution control technologies, replacement generation, undepreciated plant balances and associated operating costs from customers, there can be no assurance that Kentucky Power will be able to obtain a rate order to fully recover the remaining costs associated with such plants in the future. The failure to recover these costs could reduce Kentucky Power’s results of operations, financial condition and cash flows, and those of the Company following the closing of the Kentucky Power Transaction.

In addition, future changes to environmental laws, including with respect to the regulation of CO2 emissions, could cause the Company and Kentucky Power to incur materially higher costs than Kentucky Power has incurred to date.

Kentucky Power’s service territory experienced significant flooding as a result of severe weather experienced in late July 2022, which resulted in additional operating and capital expenditures being incurred by Kentucky Power. While a



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regulatory asset has been established for such expenditures, regulatory review of those expenditures would not occur until Kentucky Power’s next rate case, which is expected to be filed in 2023. As a result, the Company’s financial condition, cash flows and results of operations could be adversely impacted based on the determination made in that case.

International Investment Risk

The Company operates in markets, or may pursue growth opportunities in new markets, that are subject to regulation by various foreign governments and regulatory authorities and to the application of foreign laws. Such foreign laws or regulations may not provide the same type of legal certainty and rights, in connection with the Company’s contractual relationships in such countries, as are afforded to the Company in Canada and the U.S., which may adversely affect the Company’s ability to receive revenues or enforce its rights in connection with any operations or projects in such jurisdictions. In addition, the laws and regulations of some countries may limit the Company’s ability to hold a majority interest in certain projects, thus limiting the Company’s ability to control the operations of such projects. Any existing or new operations or interests of the Company may also be subject to significant political, economic and financial risks, which vary by country, and may include: (i) changes in government laws, policies or personnel or a country's constitution; (ii) changes in general economic conditions; (iii) restrictions on currency transfer or convertibility; (iv) changes in labour relations; (v) political instability and civil unrest; (vi) regulatory or other changes adversely affecting the local utility market; (vii) breach or repudiation of important contractual undertakings and expropriation and confiscation of assets and facilities without compensation or compensation that is less than fair market value; (viii) less developed or efficient financial markets than in North America; (ix) the absence of uniform accounting, auditing and financial reporting standards, practices and disclosure requirements; (x) less government supervision and regulation; (xi) a less developed legal or regulatory environment, including uncertainty in outcomes and actions that may be inconsistent with the rule of law; (xii) heightened exposure to corruption risk; (xiii) political hostility to investments by foreign investors, including laws affecting foreign ownership; (xiv) less publicly available information in respect of companies; (xv) adversely higher or lower rates of inflation; (xvi) higher transaction costs; and (xvii) fewer investor protections.

The Company may suffer a significant loss resulting from fraud, bribery, corruption or other illegal acts, or from inadequate or failed internal processes or systems. The Company operates in multiple jurisdictions and it is possible that its operations and development activities may expand into new jurisdictions. Doing business in multiple jurisdictions requires the Company to comply with the laws and regulations of such jurisdictions. These laws and regulations may apply to the Company, its subsidiaries, individual directors, officers, employees and third-party agents. The Company is also subject to anti-bribery and anti-corruption laws, including the Canadian Corruption of Foreign Public Officials Act and the U.S. Foreign Corrupt Practices Act. As the Company makes acquisitions and pursues development activities internationally, it is exposed to increased corruption-related risks, including potential violations of applicable anti-corruption laws.

The Company relies on its infrastructure, controls, systems and personnel, as well as central groups focusing on enterprise-wide management of specific operational risks such as fraud, trading, outsourcing, and business disruption, to manage the risk of illegal and corrupt acts or failed systems. The Company also relies on its employees and certain third parties to comply with its policies and processes as well as applicable laws. The failure to adequately identify or manage these risks, and the acquisition of businesses with weak internal controls to manage the risk of illegal or corrupt acts, could result in direct or indirect financial loss, regulatory censure and/or harm to the Company’s reputation.

Risks Specific to the Atlantica Investment

The Company’s investment in Atlantica exposes the Company to certain risks that are particular to Atlantica’s business and the markets in which Atlantica operates.

Atlantica owns, manages and acquires renewable energy, conventional power, electric transmission lines and water assets in certain jurisdictions where the Company may not operate. The Company, through its investment in Atlantica, is indirectly exposed to certain risks that are particular to the markets in which it operates, including, but not limited to, risks related to: conditions in the global economy; changes to national and international laws, political, social and macroeconomic risks relating to the jurisdictions in which Atlantica operates, including in emerging markets, which could be subject to economic, social and political uncertainties; anti-bribery and anti-corruption laws and substantial penalties and reputational damage from any non-compliance therewith; significant currency exchange rate fluctuations; Atlantica’s ability to identify and/or consummate future acquisitions on favourable terms or at all; Atlantica’s inability to replace, on similar or commercially favourable terms, expiring or terminated offtake agreements; termination or revocation of Atlantica’s concession agreements or offtake agreements; and various other factors. These risks could affect the profitability and growth of Atlantica’s business, and ultimately the profitability of the Company’s anticipated investment therein. On February 21, 2023, Atlantica announced that its board of directors has commenced a process to explore and evaluate potential strategic alternatives to maximize shareholder value (the “Atlantica Strategic Review”). There is a risk that the Atlantica Strategic Review could result in the approval or completion of a transaction or other change in Atlantica's business strategy that is not aligned with the Company’s interests. If any of the foregoing were to occur, the value of the Company’s investment could decrease and the Company’s financial condition, results of operations and cash flows could be adversely affected.



Algonquin Power & Utilities Corp. - Management Discussion & Analysis

The Company’s international activities and operations, including through the Liberty JV, expose the Company to similar risks and could likewise affect the profitability, financial condition and growth of the Company.

The Company accounts for its investment in Atlantica using the Fair Value Method (see Note 8(a) in the annual consolidated financial statements). AQN records in the consolidated statement of operations the fluctuations in the fair value of Atlantica shares and dividend income when it is declared. Dividends declared and paid by Atlantica are made at the discretion of Atlantica’s board of directors. The Company does not control the board of directors of Atlantica. Therefore, there can be no assurance that dividends will continue to be paid on Atlantica’s ordinary shares, will continue to be paid at the same rate as they are currently being paid or will be paid at any specified target rate. A loss of Atlantica dividend income, as a result of any reduction or suspension by Atlantica of its dividend or in the event that the Company were to dispose of its equity interest in Atlantica, could have a material adverse impact on the Company's cash flows and net income.

Joint Venture Investment Risk

The Company has, and may in the future continue to have, an equity interest of 50% or less and/or partners in certain projects and facilities, including those owned by the joint venture between the Company and funds managed by the Infrastructure and Power strategy of Ares Management LLC. As a result, the Company may not control such projects and facilities and its interest may be subject to the decision-making of third parties, and the Company may be reliant on a third party’s personnel, good faith, contractual compliance, expertise, historical performance, technical resources and information systems, proprietary information and judgment in providing the services. This may limit the Company’s flexibility and financial returns with respect to these projects and facilities, and create risks to the Company, including that the joint venture partner may:

•have economic or business interests or goals that are inconsistent with the Company’s economic or business interests or goals;

•take actions contrary to the Company’s policies or objectives with respect to the Company’s investments;

•have to give its consent with respect to certain major decisions, including among others, decisions relating to funding and transactions with affiliates;

•become bankrupt, limiting its ability to meet calls for capital contributions and potentially making it more difficult to refinance or sell projects;

•become engaged in a dispute with the Company that might affect the Company’s ability to develop a project;

•have competing interests in the Company’s markets that could create conflict of interest issues; or

•have different accounting policies than the Company.

The Liberty JV (through Liberty Development Energy Solutions B.V.) is a party to a secured credit facility in the amount of $306.5 million (the “Liberty JV Secured Credit Facility”) and holds a preference share ownership interest in Liberty (AY Holdings) B.V. (“AY Holdings”). The Liberty JV Secured Credit Facility is collateralized through a pledge of Atlantica ordinary shares held by AY Holdings. A collateral shortfall would occur if the net obligation (as defined in the credit agreement) would equal or exceed 50% of the market value of such Atlantica shares. In the event of a collateral shortfall, the Liberty JV is required to prepay a portion of the loan or post additional collateral in cash to reduce the net obligation to 40% of the total collateral provided (the “Collateral Reset Level”). If the Liberty JV were unable to fund the collateral shortfall, or certain other events of default occur, the Liberty JV Secured Credit Facility lenders hold the right to sell Atlantica shares to pay amounts outstanding under the facility, including reducing the facility to the Collateral Reset Level. The Liberty JV Secured Credit Facility is repayable on demand if Atlantica ceases to be a public company or if certain other events are announced or completed that could restrict the Company’s ability to sell or transfer its Atlantica ordinary shares. If the Liberty JV were unable to repay the amounts owed, the lenders would have the right to realize on their collateral.

The Company has entered into Equity Capital Contribution Agreements ("ECCA") with certain of its project development entities it holds an equity interest in. The ECCAs obligate the Company to provide funding upon the realization of certain completion milestones related to the projects under development. The ECCAs have been pledged as collateral against construction loans obtained by the project entities and may require the Company to fund in amounts in excess of the underlying value of the assets. The Company has also provided guarantees of performance for certain development projects owned by the equity investees. The Company's maximum exposure to loss (as defined in U.S. GAAP under ASC 810) on these agreements and guarantees is $658.2 million.

Please refer to Note 8 in the annual consolidated financial statements for a description of the Company's Long Term Investments and Notes Receivable.



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Dispositions

Asset Retirement Obligations

AQN and its subsidiaries complete periodic reviews of potential asset retirement obligations that may require recognition. As part of this process, AQN and its subsidiaries consider the contractual requirements outlined in their operating permits, leases, and other agreements, the probability of the agreements being extended, the ability to quantify such expense, the timing of incurring the potential expenses, as well as other factors which may be considered in evaluating if such obligations exist and in estimating the fair value of such obligations.

In conjunction with acquisitions and developed projects, the Company assumed certain asset retirement obligations. The asset retirement obligations mainly relate to legal requirements for: (i) removal or decommissioning of power generating facilities; (ii) cut (disconnect from the distribution system), purge (clean of natural gas and PCB contaminants), and cap natural gas mains within the natural gas distribution and transmission system when mains are retired in place, or dispose of sections of natural gas mains when removed from the pipeline system; (iii) clean and remove storage tanks containing waste oil and other waste contaminants; and (iv) remove asbestos upon major renovation or demolition of structures and facilities.

Cycles and Seasonality

Regulated Services Group

The Regulated Services Group's demand for water is affected by weather conditions and temperature. Demand for water during warmer months is generally greater than cooler months due to requirements for irrigation, swimming pools, cooling systems and other outside water use. If there is above normal rainfall or rainfall is more frequent than normal the demand for water may decrease, adversely affecting revenues.

The Regulated Services Group's demand for energy from its electric distribution systems is primarily affected by weather conditions and conservation initiatives. The Regulated Services Group provides information and programs to its customers to encourage the conservation of energy. In turn, demand may be reduced which could have short-term adverse impacts on revenues.

The Regulated Services Group's primary demand for natural gas from its natural gas distribution systems is driven by the seasonal heating requirements of its residential, commercial, and industrial customers. The colder the weather, the greater the demand for natural gas to heat homes and businesses. As such, the natural gas distribution systems demand profile typically peaks in the winter months of January and February and declines in the summer months of July and August. Year to year variability also occurs depending on how cold the weather is in any particular year.

There is a risk that climate change impacts the seasonality and demand for water, electricity and natural gas.

The Company attempts to mitigate the above noted risks by seeking regulatory mechanisms during rate review proceedings. While not all regulatory jurisdictions have approved mechanisms to mitigate demand fluctuations, to date, the Regulated Services Group has successfully obtained regulatory approval to implement such decoupling mechanisms in 7 of 13 states. An example of such a mechanism is seen at the Peach State Gas System in Georgia, where a weather normalization adjustment is applied to customer bills during the months of October through May that adjusts commodity rates to stabilize the revenues of the utility for changes in billing units attributable to weather patterns.

Renewable Energy Group

The Renewable Energy Group's hydroelectric operations are impacted by seasonal fluctuations and year to year variability of the available hydrology. These assets are primarily “run-of-river” and as such fluctuate with natural water flows. During the winter and summer periods, flows are generally lower, while during the spring and fall periods flows are generally higher. The ability of these assets to generate income may be impacted by changes in water availability or other material hydrologic events within a watercourse. Year to year, the level of hydrology varies, impacting the amount of power that can be generated in a year.

The Renewable Energy Group's wind generation facilities are impacted by seasonal fluctuations and year to year variability of the wind resource. During the fall, winter and spring periods, winds are generally stronger than during the summer



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period. The ability of these facilities to generate income may be impacted by naturally occurring changes in wind patterns and wind strength.

The Renewable Energy Group's solar generation facilities are impacted by seasonal fluctuations and year to year variability in solar radiance. For instance, there are more daylight hours in the summer than there are in the winter, resulting in higher production in the summer months. The ability of these facilities to generate income may be impacted by naturally occurring changes in solar radiance, such as cloud cover and snow.

The Company attempts to mitigate the above noted natural resource fluctuation risks by acquiring or developing generating stations in different geographic locations.

Development and Construction Risk

The Company actively engages in the development and construction of new power generation facilities. There can be no assurance that the Corporation will be able to identify attractive acquisition or development candidates in the future or that it will be able to realize growth opportunities that improve the Corporation's financial results or increase the amount of cash available for distribution There is always a risk that material delays, technical issues with interconnection and the interconnection utility, required upgrades to interconnection facilities, required curtailments of generation, delays in obtaining interconnection rights, and/or cost overruns or lost revenue could be incurred in any of the projects planned or currently in construction affecting the Company’s overall performance. There are risks that actual costs may exceed budget estimates, delays may occur in obtaining permits and materials, suppliers and contractors may not perform as required under their contracts, warranties under contracts may be unfilled or insufficient, there may be inadequate availability, productivity or increased cost of qualified craft or local labour, start-up activities may take longer than planned, curtailment of a facility's output may be required, the scope, actual or expected returns, and timing of projects may change, and other events beyond the Company's control may occur, in each case that may materially affect the viability, schedule, budget, cost and performance of projects. Regulatory approvals can be challenged by a number of mechanisms which vary across state and provincial jurisdictions. Such permitting challenges could identify issues that may result in permits being modified or revoked.

Risks Specific to Renewable Generation Projects:

The strength and consistency of the wind resource will vary from the estimate set out in the initial wind studies that were relied upon to determine the feasibility of the wind facility. If weather patterns change or the historical data proves not to accurately reflect the strength and consistency of the actual wind, the assumptions underlying the financial projections as to the amount of electricity to be generated by the facility may be different and cash could be impacted.

The amount of solar radiance will vary from the estimate set out in the initial solar studies that were relied upon to determine the feasibility of the solar facility. If weather patterns change or the historical data proves not to accurately reflect the strength and consistency of the solar radiance, the assumptions underlying the financial projections as to the amount of electricity to be generated by the facility may be different and cash could be impacted.

For certain of its development projects, the Company relies on financing from third party tax equity investor, the participation of which depends upon qualification of the project for U.S, tax incentives and satisfaction of the investors' investment criteria. These investors typically provide funding upon commercial operation of the facility. Should certain facilities not meet the conditions required for tax equity funding, expected returns from the facilities may be adversely impacted.

Litigation Risks and Other Contingencies

AQN and certain of its subsidiaries are involved in various litigation, claims and other legal and regulatory proceedings that arise from time to time in the ordinary course of business. Any accruals for contingencies related to these items are recorded in the financial statements at the time it is concluded that a material financial loss is likely and the related liability is estimable. Anticipated recoveries under existing insurance policies are recorded when reasonably assured of recovery.

Mountain View Fire



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amounts paid and to be paid to their insureds. The likelihood of success in these lawsuits cannot be reasonably predicted. Liberty CalPeco intends to vigorously defend them. The Company has wildfire liability insurance that is expected to apply up to applicable policy limits.

Apple Valley Condemnation Proceedings

On January 7, 2016, the Town of Apple Valley filed a lawsuit seeking to condemn the utility assets of Liberty Utilities (Apple Valley Ranchos Water) Corp. (“Liberty Apple Valley”). On May 7, 2021, the Court issued a Tentative Statement of Decision denying the Town of Apple Valley’s attempt to take the Apple Valley water system by eminent domain. The ruling confirmed that Liberty Apple Valley’s continued ownership and operation of the water system is in the best interest of the community. On October 14, 2021, the Court issued the Final Statement of Decision. The Court signed and entered an Order of Dismissal and Judgment on November 12, 2021. On January 7, 2022, the Town filed a notice of appeal of the judgment entered by the Court. On August 2, 2022, the Court issued a ruling awarding Liberty Apple Valley approximately $13.2 million in attorney’s fees and litigation costs. The Town filed a notice of appeal of the fee award on August 22, 2022. The Town’s appeal of the condemnation judgment and fee award have been consolidated into one appellate docket.

Information Security Risk

The Company relies upon its and third-party information and operational technology networks, systems and devices to process, transmit and store electronic information, and to manage and support a variety of business processes and activities and safely operate its assets. The Company also uses its and third-party information technology systems to record, process and summarize financial information and results of operations for internal reporting purposes and to comply with financial reporting, legal and tax requirements. The Company’s and certain of its third-party vendors' technology networks, systems and devices collect and store sensitive data, including system operating information, proprietary business information belonging to the Company and third parties, as well as personal information belonging to the Company’s customers, employees and other stakeholders. As the Company operates critical infrastructure, it may be at an increased risk of cyber-attacks or other security threats by third parties.

The Company’s, its third-party vendors’ or other counterparties' technology systems and technology networks, devices and infrastructure may be vulnerable to damage, disruptions or shutdowns due to attacks by hackers or breaches due to employee error or malfeasance, disruptions during software or hardware upgrades, telecommunication failures, theft, politically-driven attacks (including as a result of the conflict between Russia and Ukraine, and any associated sanctions imposed or actions taken by the United States, Canada or other countries or retaliatory measures by Russia), acts of war or terrorism, natural disasters or other similar events. In addition, certain sensitive information and data may be stored by the Company on physical devices, in physical files and records on its premises or transmitted to the Company verbally, subjecting such information and data to a risk of loss, theft, release and misuse. Methods used to attack critical assets could include general purpose or industry specific malware delivered via network transfer, removable media, viruses, attachments, or links in e-mails. The methods used by attackers are continuously evolving and can be difficult to predict and detect. The occurrence of any of these events could negatively impact the Company’s operations, power generation facilities and utility distribution and transmission systems; could cause services disruptions or system failures; could adversely affect safety; could expose the Company, its customers or its employees to a risk of loss or misuse of information; could affect the ability to earn or collect revenue or correctly record, process and report financial information; and could result in increased costs, legal claims or proceedings, liability or regulatory penalties against the Company, damage the Company’s reputation or otherwise harm the Company’s business.

The long-term impact of terrorist attacks and cyber-attacks and the magnitude of the threat of future terrorist attacks and cyber-attacks on the utility and power generation industries in general, and on the Company in particular, cannot be known. Increased security measures to be taken by the Company as a precaution against possible terrorist attacks and cyber-attacks may result in increased costs to the Company. The Company must also comply with data privacy laws in each of the jurisdictions in which it operates. Certain data privacy laws and other cybersecurity regulations have expanded in recent years, leading to increased obligations, and fines for breaches of such laws and regulations have increased. The Company may incur additional costs to maintain compliance, or significant financial penalties, in the event of a breach.

The Company cannot accurately assess the probability that a security breach may occur or accurately quantify the potential impact of such an event. The Company provides no assurance that it will be able to identify, protect against and remedy all cybersecurity, physical security or system vulnerabilities or that unauthorized access or errors will be identified and remedied. Should a breach occur, the Company may suffer costs, losses, and damages, all or some of which may not be recoverable through insurance, legal, regulatory, or other processes, and could materially adversely affect the Company’s business and results of operations including its reputation with customers, regulators, governments, and financial markets. Resulting costs could include, among others, response, recovery (including ransom costs), and remediation costs, increased protection or insurance costs, and costs arising from damages and losses incurred by third parties.



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disruptions of supplies and markets for products of the Company, and the possibility that the Company’s operations or facilities could be direct targets of, or indirect casualties of, an act of terror or cyber-security attack. The effects of hostilities, military campaigns or terrorist or cyber-security attacks could include disruption to the Company’s generation, transmission and distribution systems or to the electrical grid in general, and could result in a decline in the general economy and have a material adverse effect on the Company.

Technology Infrastructure Implementation Risk

The Company relies upon various information and operational technology infrastructure systems to carry out its business processes and operations. This subjects the Company to inherent costs and risks associated with maintaining, upgrading, replacing and changing information and operational technology systems. This includes impairment of its technology systems, potential disruption of operations, business process and internal control systems, substantial capital expenditures, demands on management time and other risks of delays, and difficulties in upgrading, transitioning and integrating technology systems.

AQN and certain of its subsidiaries are in the process of updating their technology infrastructure systems through the implementation of an integrated customer solution platform, which is expected to include customer billing, enterprise resource planning systems and asset management systems. The implementation of these systems is being managed by a dedicated team. Following successful pilot implementations, deployment began in 2022 and is expected to occur in a phased approach across the enterprise through 2024. The implementation of such technology systems will require the investment of significant financial and human resources. Disruptions, delays or deficiencies in the design, implementation, or operation of these technology systems or integration of these systems with other existing information technology or operations technology could: adversely affect the Company’s operations, including its ability to monitor its business, pay its suppliers, bill its customers, and report financial information accurately and on a timely basis; lead to higher than expected costs; lead to increased regulatory scrutiny or adverse regulatory consequences; or result in the failure to achieve the expected benefits. As a result, the Company’s operations, financial condition, cash flows and results of operations could be adversely affected.

Energy Consumption and Advancement in Technologies Risk

The Company’s generation, distribution and transmission assets are affected by energy and water demand, sales and operating costs, among other things, in the jurisdictions in which they operate. Demand, sales and operating costs may change as a result of, among other things, fluctuations in general economic conditions, energy and commodity prices, inflation, interest rates, employment levels, personal disposable income, customer preferences, advancements in new technologies, population or demographic changes and housing starts. Significantly reduced energy or water demand in the Company’s service territories could reduce capital spending forecasts, and specifically capital spending related to new customer growth. A reduction in capital spending could, in turn, affect the Company’s rate base and earnings growth. A downturn in economic conditions may have an adverse effect on the Company’s results of operations, financial condition and cash flows despite regulatory measures, where applicable, available to compensate for some or all of the reduced demand and increased costs, which recovery, if any, may lag costs incurred by the Company. In addition, an extended decline in economic conditions could make it more difficult for customers to pay for the utility services they consume, thereby affecting the aging and collection of the utilities’ trade receivables.

The emergence of initiatives designed to reduce greenhouse gas emissions and control or limit the effects of climate change has resulted in incentives and programs to increase energy efficiency and reduce water and energy consumption, including efforts to reduce the availability and reliance on natural gas. There may also be efforts to move to deregulation in certain of the markets in which the Regulated Services Group operates, which could adversely affect the Company's business, financial condition and results of operations.

Increased adoption of these practices, requirements and technologies could reduce demand for utility-scale electricity generation and electric, water, and natural gas distribution, and as a result, the Company’s business, financial condition and results of operations could be adversely affected.

The Company may also invest in and use newly developed, less proven, technologies or generation methods in its development and construction projects or in maintaining or enhancing its existing operations and assets. There is no guarantee that such new technologies will perform as anticipated. The failure of a new technology or generation method to perform as anticipated may adversely affect the profitability of a particular development project or existing operations and assets.



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The Regulated Services Group seeks to actively engage with regulators, governments and customers, as appropriate, in an effort to ensure these changes in consumption do not negatively impact the services provided.

Uninsured Risk

The Company maintains insurance coverage for certain exposures, but this coverage is limited and the Company is generally not fully insured against all significant losses. Insurance coverage for the Company is subject to policy conditions and exclusions, coverage limits, and various deductibles, and not all types of liabilities and losses may be covered by insurance. Further, certain assets and facilities of the Company are not fully insured, as the cost of the coverage is not economically viable or is not otherwise available. Insurance may not continue to be offered on an economically feasible basis, or at all, and may not cover all events that could give rise to a loss or claim involving the Company’s assets or operations. There can also be no assurance that insurers will fulfill their obligations. The Company’s ability to obtain and maintain insurance and the terms of any available insurance coverage could be materially adversely affected by international, national, state or local events and company-specific events, as well as the financial condition of insurers.

If the Company were to incur a serious uninsured loss or a loss significantly exceeding the limits of its insurance policies, the results could have a material adverse effect on the Company’s business, results of operations, financial condition and cash flows. In the event of a large uninsured loss, including those caused by severe weather conditions, natural disasters and certain other events beyond the control of the Regulated Services Group, the Company may make an application to an applicable regulatory authority for the recovery of these costs through customer rates to offset any loss. However, the Company cannot provide assurance that the regulatory authorities would approve any such application in whole or in part. This potential recovery mechanism is not available to the Renewable Energy Group.

QUARTERLY FINANCIAL INFORMATION

The following is a summary of unaudited quarterly financial information for the eight quarters ended December 31, 2022:


(all dollar amounts in $ millions except per share information)	1st Quarter 2022		2nd Quarter 2022		3rd Quarter 2022		4th Quarter 2022
Revenue	$	733.2	$	619.4	$	664.6	$	748.0

Net earnings (loss) attributable to shareholders	91.0		(33.4)		(195.2)		(74.4)

Net earnings (loss) per share	0.13		(0.05)		(0.29)		(0.11)
Diluted net earnings (loss) per share	0.13		(0.05)		(0.29)		(0.11)
Adjusted Net Earnings1	141.3		109.7		72.8		151.0
Adjusted Net Earnings per common share1	0.21		0.16		0.11		0.22
Adjusted EBITDA1	330.6		289.3		278.5		358.3
Total assets	17,669.9		17,737.9		17,653.3		17,627.6
Long term debt2	7,191.6		7,455.4		7,705.1		7,512.3
Dividend declared per common share	$	0.17	$	0.18	$	0.18	$	0.18

	1st Quarter 2021		2nd Quarter 2021		3rd Quarter 2021		4th Quarter 2021
Revenue	$	633.6	$	524.1	$	524.4	$	592.0

Net earnings (loss) attributable to shareholders	13.9		103.2		(27.9)		175.6

Net earnings (loss) per share	0.02		0.16		(0.05)		0.27
Diluted net earnings (loss) per share	0.02		0.16		(0.05)		0.26
Adjusted Net Earnings1	124.5		91.7		96.0		137.0
Adjusted Net Earnings per common share1	0.20		0.15		0.15		0.21
Adjusted EBITDA1	282.9		244.8		250.3		298.3
Total assets	15,286.1		16,453.7		16,699.0		16,797.5
Long term debt2	6,353.7		6,622.6		6,870.3		6,211.7
Dividend declared per common share	$	0.16	$	0.17	$	0.17	$	0.17


1			See Caution Concerning Non-GAAP Measures.
2			Includes current portion of long-term debt, long-term debt and convertible debentures.

The quarterly results are impacted by various factors including seasonal fluctuations and acquisitions of facilities as noted in this MD&A.



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Quarterly revenues have fluctuated between $524.1 million and $748.0 million over the prior two year period. A number of factors impact quarterly results including acquisitions, seasonal fluctuations, and winter and summer rates built into the PPAs. In addition, a factor impacting revenues year over year is the fluctuation in the strength of the Canadian dollar relative to the U.S. dollar which can result in significant changes in reported revenue from Canadian operations.

Quarterly net earnings attributable to shareholders have fluctuated between a loss of $195.2 million and earnings of $175.6 million over the prior two year period. Earnings have been significantly impacted by non-cash factors such as deferred tax recovery and expense, impairment of intangibles, property, plant and equipment and mark-to-market gains and losses on financial instruments.

SUMMARY FINANCIAL INFORMATION OF ATLANTICA

The Company owns an approximately 42% beneficial interest in Atlantica. AQN accounts for its interest in Atlantica using the fair value method (see Note 8(a) in the annual consolidated financial statements). The summary financial information of Atlantica in the following table is derived from the consolidated financial statements of Atlantica as of December 31, 2022 and 2021 and for the years then ended which are reported in U.S. dollars and were prepared using International Financial Reporting Standards, as issued by the International Accounting Standards Board ("IFRS"). The recognition, measurement and disclosure requirements of IFRS differ from U.S. GAAP as applied by the Company.


(all dollar amounts in $ millions)	2022		2021
Revenue	$	1,102.0	$	1,211.7
Loss for the year	(2.1)		(10.9)
Total non-current assets	8,069.2		8,585.0
Total current assets	1,031.7		1,166.9
Total non-current liabilities	6,792.9		7,178.9
Total current liabilities	519.0		824.4

DISCLOSURE CONTROLS AND PROCEDURES

AQN's management carried out an evaluation as of December 31, 2022, under the supervision of and with the participation of AQN’s Chief Executive Officer ("CEO") and Chief Financial Officer ("CFO"), of the effectiveness of the design and operations of AQN’s disclosure controls and procedures (as defined in Rule 13a-15(e) and Rule 15d-15(e) under the Securities Exchange Act of 1934, as amended (the “Exchange Act”)). Based on that evaluation, the CEO and the CFO have concluded that as of December 31, 2022, AQN’s disclosure controls and procedures are effective to provide reasonable assurance that information required to be disclosed by AQN in reports that it files or submits under the Exchange Act is recorded, processed, summarized, and reported within the time periods specified in rules and forms of the U.S. Securities and Exchange Commission, and is accumulated and communicated to management, including the CEO and CFO, as appropriate, to allow timely decisions regarding required disclosure.

Management Report on Internal Controls over Financial Reporting

Management, including the CEO and the CFO, is responsible for establishing and maintaining internal control over financial reporting (as defined in Rules 13a-15(f) under the Exchange Act) to provide reasonable, but not absolute, assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with U.S. GAAP.

The Company's internal control over financial reporting framework includes those policies and procedures that (i) pertain to the maintenance of records that, in reasonable detail, accurately and fairly reflect the transactions and dispositions of the assets of the Company, (ii) provide reasonable assurance that transactions are recorded as necessary to permit preparation of financial statements in accordance with U.S. GAAP, and that receipts and expenditures of the Company are being made only in accordance with authorizations of management and directors of the Company; and (iii) provide reasonable assurance regarding prevention or timely detection of unauthorized acquisition, use or disposition of the Company's assets that could have a material effect on the Company's consolidated financial statements.

Management assessed the effectiveness of the Company's internal control over financial reporting as of December 31, 2022, based on the framework established in Internal Control - Integrated Framework (2013) issued by COSO. This assessment included review of the documentation of controls, evaluation of the design effectiveness of controls, testing of the operating effectiveness of controls, and a conclusion on this evaluation. Based on this assessment, management concluded that the Company's internal control over financial reporting was effective as of December 31, 2022 to provide reasonable assurance regarding the reliability of financial reporting and the preparation of consolidated financial



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statements for external reporting purposes in accordance with U.S. GAAP. Management reviewed the results of its assessment with the Audit Committee of the Board of Directors of AQN.

The Company acquired Liberty NY Water effective January 1, 2022. The financial information for this acquisition is included in this MD&A and in Note 3 to the annual consolidated financial statements. Liberty NY Water contributed $125.4 million in revenue and $21.8 million in operating income, representing approximately 5% and 4% of the Company's consolidated revenue and operating income, respectively, for the year ended December 31, 2022. Liberty NY Water represented approximately 4% of the Company's total consolidated assets, and 3% of the Company's total consolidated liabilities, respectively, as of December 31, 2022. National Instrument 52-109 and the U.S. Securities and Exchange Commission provide an exemption whereby companies undergoing acquisitions can exclude the acquired business in the year of acquisition from the scope of testing and assessment of design and operational effectiveness of controls over financial reporting. Due to the complexity associated with assessing internal controls during integration efforts, the Company has utilized the scope exemption as it relates to this acquisition in its management report on internal controls over financial reporting for the year ending December 31, 2022.

Changes in Internal Controls over Financial Reporting

Management assessed the design and operating effectiveness of the changed controls based on the same framework established in Internal Control - Integrated Framework (2013) issued by COSO as at and through December 31, 2022. Except as described above, there have been no further changes in the Company’s internal control over financial reporting that occurred that have materially affected, or are reasonably likely to materially affect, the Company’s internal control over financial reporting.

Inherent Limitations on Effectiveness of Controls

Due to its inherent limitations, disclosure controls and procedures or internal control over financial reporting may not prevent or detect all misstatements based on error or fraud. Further, the effectiveness of internal control is subject to the risk that controls may become inadequate because of changes in conditions, or that the degree of compliance with policies or procedures may change.

CRITICAL ACCOUNTING ESTIMATES AND POLICIES

AQN prepared its annual consolidated financial statements in accordance with U.S. GAAP. The preparation of the annual consolidated financial statements requires management to make estimates and assumptions that affect the reported amounts of assets and liabilities, related amounts of revenues and expenses, and disclosure of contingent assets and liabilities. Significant areas requiring the use of management judgment relate to the scope of consolidated entities, the recoverability of assets, the measurement of deferred taxes and the recoverability of deferred tax assets, rate-regulation, unbilled revenue, pension and post-employment benefits, fair value of derivatives and fair value of assets and liabilities acquired in a business combination. Actual results may differ from these estimates.

AQN’s significant accounting policies and new accounting standards are discussed in Notes 1 and 2 in the annual consolidated financial statements, respectively. Management believes the following accounting policies involve the application of critical accounting estimates. Accordingly, these accounting estimates have been reviewed and discussed with the Audit Committee of the Board of Directors of AQN.

Consolidation and Variable Interest Entities

The Company uses judgment to assess whether its operations or investments represent variable interest entities ("VIEs"). In making these evaluations, management considers (a) the sufficiency of the investment's equity at risk, (b) the existence of a controlling financial interest, and (c) the structure of any voting rights. In addition, management considers the specific facts and circumstances of each investment in a VIE when determining whether the Company is the primary beneficiary. The factors that management takes into consideration include the purpose and design of the VIE, the key decisions that affect its economic performance, whether the parties to the arrangements are related parties or de facto agents of the Company, and whether the Company has the power to direct the activities that would most significantly affect the economic performance of the VIE. Management's judgment is also required to determine whether the Company has the right to receive benefits or the obligation to absorb losses of the VIE. Based on the judgments made, the Company will consolidate the VIE if it determines that it is the primary beneficiary.



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Estimated Useful Lives and Recoverability of Long-Lived Assets, Intangibles Assets, Goodwill and Long-term Investments

The Company makes judgments (a) to determine the recoverability of a development project, and the period over which the costs are capitalized during the development and construction of the project, (b) to assess the nature of the costs to be capitalized, (c) to distinguish individual components and major overhauls, and (d) to determine the useful lives or unit-of-production over which assets are depreciated.

Depreciation rates on most utility assets are subject to regulatory review and approval, and depreciation expense is recovered through rates set by ratemaking authorities. The recovery of those costs is dependent on the ratemaking process.

The carrying value of long-lived assets, intangible assets, goodwill and long-term investments, is reviewed whenever events or changes in circumstances indicate that such carrying values may not be recoverable, and at least annually for goodwill. Equity method investments are reviewed to determine whether an other-than-temporary decline in value has occurred and an impairment exists. Some of the factors AQN considers as indicators of impairment include a significant change in operational or financial performance, unexpected outcome from rate orders, natural disasters, energy pricing and changes in regulation. When such events or circumstances are present, the Company assesses whether the carrying value will be recovered through the expected future cash flows. If the facility includes goodwill, the fair value of the facility is compared to its carrying value. Both methodologies are sensitive to the forecasted cash flows and in particular energy prices, long-term growth rate and, discount rate for the fair value calculation.

In 2022 and 2021, management assessed qualitative and quantitative factors for each of the reporting units that were allocated goodwill. No goodwill impairment provision was required. During the fourth quarter of 2022, the Company recorded an impairment charge of $235.5 million to reduce the carrying value of its investment in the Texas Coastal Wind Facilities and the carrying value of the Senate Wind Facility which began commercial operations in 2012. These impaired assets operate within the ERCOT market, and the 2022 Impairment recorded is primarily due to declining forecasted energy prices in ERCOT for the Senate Wind Facility and continued challenges with congestion at the Texas Costal Wind Facilities. The Company determined fair value using an income approach. Changes in assumptions of revenue forecasts, driven by expected production, basis difference and resulting spot prices, projected operating and capital expenditures would affect the estimated fair value.

Valuation of Deferred Tax Assets

In assessing the realization of deferred tax assets, management aims to consider all evidence, both positive and negative, to determine whether it is more likely than not that deferred tax assets will be realized. A piece of objective evidence evaluated is cumulative earnings or losses incurred over the three-year period. Even with a cumulative loss, management will typically review a forecast of future taxable income and consider tax planning strategies before making its final assessment.

Primarily as a result of the 2022 Impairment, the U.S. entities in the Renewable Energy Group, which have historically been in an overall deferred tax liability position, were in an overall deferred tax asset position as at December 31, 2022. In the course of assessing the U.S. deferred tax assets in the Renewable Energy Group, management concluded that, during the fourth quarter of 2022, it was no longer probable that the Renewable Energy Group would generate sufficient taxable income to realize the benefit of the deferred tax assets of such group. Management’s conclusion is based on the balance of all available positive and negative evidence applicable to the Renewable Energy Group, including material impairment charges recorded on certain assets, insufficient taxable temporary differences to allow the full utilization of the deferred tax asset, insufficient forecasted taxable income and a historical 3-year cumulative loss position. The amount of the deferred tax asset considered realizable could be adjusted if estimates of future taxable income during the carryforward period are reduced or increased or if objective negative evidence in the form of cumulative losses is no longer present and additional weight is given to subjective evidence such as management projections for growth.

Accounting for Rate Regulation

Accounting guidance for regulated operations provides that rate-regulated entities account for and report assets and liabilities consistent with the recovery of those incurred costs in rates if the rates established are designed to recover the costs of providing the regulated service and if the competitive environment makes it probable that such rates can be charged and collected. This accounting guidance is applied to the Regulated Services Group's operations, with the exception of ESSAL.

Certain expenses and revenues subject to utility regulation or rate determination normally reflected in income are deferred on the balance sheet as regulatory assets or liabilities and are recognized in income as the related amounts are included in service rates and recovered from or refunded to customers. Regulatory assets and liabilities are recorded when it is probable that these items will be recovered or reflected in future rates. Determining probability requires significant judgment on the part of management and includes, but is not limited to, consideration of testimony presented in regulatory hearings, proposed regulatory decisions, final regulatory orders and industry practice. If events were to occur that would



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make the recovery of these assets and liabilities no longer probable, these regulatory assets and liabilities would be required to be written off or written down.

Unbilled Energy Revenues

Revenues related to natural gas, electricity and water delivery are generally recognized upon delivery to customers. The determination of customer billings is based on a systematic reading of meters throughout the month. At the end of each month, amounts of natural gas, energy or water provided to customers since the date of the last meter reading are estimated, and the corresponding unbilled revenue is recorded. Factors that can impact the estimate of unbilled energy include, but are not limited to, seasonal weather patterns compared to normal, total volumes supplied to the system, line losses, economic impacts, and composition of customer classes. Estimates are reversed in the following month and actual revenue is recorded based on subsequent meter readings.

Derivatives

AQN uses derivative instruments to manage exposure to changes in commodity prices, foreign exchange rates, and interest rates. Management’s judgment is required to determine if a transaction meets the definition of a derivative and, if it does, whether the normal purchases and sales exception applies or whether individual transactions qualify for hedge accounting treatment. Management’s judgment is also required to determine the fair value of derivative transactions. AQN determines the fair value of derivative instruments based on forward market prices in active markets obtained from external parties adjusted for nonperformance risk. A significant change in estimate could affect AQN’s results of operations if the hedging relationship was considered no longer effective.

Pension and Post-employment Benefits

The obligations and related costs of defined benefit pension and post-employment benefit plans are calculated using actuarial concepts, which include critical assumptions related to the discount rate, mortality rate, compensation increase, expected rate of return on plan assets and medical cost trend rates. These assumptions are important elements of expense and/or liability measurement and are updated on an annual basis, or upon the occurrence of significant events. The mortality assumption for December 31, 2022 uses the Pri-2012 mortality table and the projected generationally scale MP-2021, adjusted to reflect the ultimate improvement rates in the 2021 Social Security Administration intermediate assumptions for plans in the United States. The mortality assumption for the Bermuda plan as of December 31, 2022 uses the 2014 Canadian Pensioners' Mortality Table combined with mortality improvement scale CPM-B.

The sensitivities of key assumptions used in measuring accrued benefit obligations and benefit plan cost for 2022 are outlined in the following table. They are calculated independently of each other. Actual experience may result in changes in a number of assumptions simultaneously. The types of assumptions and method used to prepare the sensitivity analysis has not changed from previous periods and is consistent with the calculation of the retirement benefit obligations and net benefit plan cost recognized in the consolidated financial statements.



Algonquin Power & Utilities Corp. - Management Discussion & Analysis


	2022 Pension Plans				2022 OPEB Plans
(all dollar amounts in $ millions)	Accrued Benefit Obligation		Net Periodic Pension Cost		Accumulated Postretirement Benefit Obligation		Net Periodic Postretirement Benefit Cost
Discount Rate
1% increase		(53.4)		(2.2)		(24.7)		(2.2)
1% decrease		63.8		6.3		30.6		4.4

Future compensation rate
1% increase		1.9		1.8		—		—
1% decrease		(1.7)		(1.7)		—		—

Expected return on plan assets
1% increase		—		(6.6)		—		(1.8)
1% decrease		—		6.6		—		1.8

Health care trend
1% increase		—		—		28.7		7.0
1% decrease		—		—		(23.5)		(4.2)

Business Combinations

The Company has completed a number of business combinations in the past few years. Management's judgment is required to estimate the purchase price, to identify and to fair value all assets and liabilities acquired. The determination of the fair value of assets and liabilities acquired is based upon management’s estimates and certain assumptions generally included in a present value calculation of the related cash flows.

Acquired assets and liabilities assumed that are subject to critical estimates include property, plant and equipment, regulatory assets and liabilities, intangible assets, long-term debt and pension and OPEB obligations. The fair value of regulated property, plant and equipment is assessed using an income approach where the estimated cash flows of the assets are calculated using the approved tariff and discounted at the approved rate of return. The fair value of regulatory assets and liabilities considers the estimated timing of the recovery or refund to customers through the rate making process. The fair value of intangible assets is assessed using a multi-period excess earnings method. The fair value of long-term debt is determined using a discounted cash flow method and current interest rates. The pension and OPEB obligations are valued by external actuaries using the guidelines of ASC 805, Business combinations.



Algonquin Power & Utilities Corp. - Management Discussion & Analysis

Exhibit 99.4

Consent of Independent Registered Public Accounting Firm

We consent to the reference to our Firm under the caption "Experts", and to the incorporation by reference in the following Registration Statements:

1. Form S-8 nos. 333-177418, 333-213648, 333-213650, 333-218810, 333-232012 and 333-238961;

2. Form F-10 no. 333-261010; and

3. Form F-3 nos. 333-220059, 333-227246 and 333-263839

of Algonquin Power and Utilities Corp. (the "Company") and the use herein of our reports dated March 17, 2023, with respect to the consolidated balance sheets as of December 31, 2022 and December 31, 2021 and the consolidated statements of operations, comprehensive income, equity and cash flows for each of the years in the two-year period ended December 31, 2022, and the effectiveness of internal control over financial reporting of the Company as of December 31, 2022, included in this Annual Report on Form 40-F.

/s/ Ernst & Young LLP

Chartered Professional Accountants, Licensed Public Accountants

Toronto, Canada

March 17, 2023

Exhibit 99.5

CERTIFICATION PURSUANT TO SECTION 302 OF THE U.S. SARBANES-OXLEY ACT OF 2002

I, Arun Banskota, certify that:

1. I have reviewed this annual report on Form 40-F of Algonquin Power & Utilities Corp.

2. Based on my knowledge, this report does not contain any untrue statement of a material fact or omit to state a material fact necessary to make the statements made, in light of the circumstances under which such statements were made, not misleading with respect to the period covered by this report;

3. Based on my knowledge, the financial statements, and other financial information included in this report, fairly present in all material respects the financial condition, results of operations and cash flows of the issuer as of, and for, the periods presented in this report;

4. The issuer's other certifying officer and I are responsible for establishing and maintaining disclosure controls and procedures (as defined in Exchange Act Rules 13a-15(e) and 15d-15(e)) and internal control over financial reporting (as defined in Exchange Act Rules 13a-15(f) and 15d-15(f)) for the issuer and have:

(a) Designed such disclosure controls and procedures, or caused such disclosure controls and procedures to be designed under our supervision, to ensure that material information relating to the issuer, including its consolidated subsidiaries, is made known to us by others within those entities, particularly during the period in which this report is being prepared;

(b) Designed such internal control over financial reporting, or caused such internal control over financial reporting to be designed under our supervision, to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles;

(c) Evaluated the effectiveness of the issuer's disclosure controls and procedures and presented in this report our conclusions about the effectiveness of the disclosure controls and procedures, as of the end of the period covered by this report based on such evaluation; and

(d) Disclosed in this report any change in the issuer's internal control over financial reporting that occurred during the period covered by the annual report that has materially affected, or is reasonably likely to materially affect, the issuer's internal control over financial reporting; and

5. The issuer's other certifying officer and I have disclosed, based on our most recent evaluation of internal control over financial reporting, to the issuer's auditors and the audit committee of the issuer's board of directors (or persons performing the equivalent functions):

(a) All significant deficiencies and material weaknesses in the design or operation of internal control over financial reporting which are reasonably likely to adversely affect the issuer's ability to record, process, summarize and report financial information; and

(b) Any fraud, whether or not material, that involves management or other employees who have a significant role in the issuer's internal control over financial reporting.

Date: March 21, 2023

By:

/s/ Arun Banskota

Name:

Arun Banskota

Title:

President and Chief Executive Officer

Exhibit 99.6

CERTIFICATION PURSUANT TO SECTION 302 OF THE U.S. SARBANES-OXLEY ACT OF 2002

I, Darren Myers, certify that:

1. I have reviewed this annual report on Form 40-F of Algonquin Power & Utilities Corp.

(b) Any fraud, whether or not material, that involves management or other employees who have a significant role in the issuer's internal control over financial reporting.

Date: March 21, 2023

By:

/s/ Darren Myers

Name:

Darren Myers

Title:

Chief Financial Officer

Exhibit 99.7

CERTIFICATION PURSUANT TO

18 U.S.C. SECTION 1350,

AS ADOPTED PURSUANT TO

SECTION 906 OF THE SARBANES-OXLEY ACT OF 2002

In connection with the Annual Report of Algonquin Power & Utilities Corp. (the “Corporation”) on Form 40-F for the year ended December 31, 2022 as filed with the Securities and Exchange Commission on the date hereof (the “Report”), I, Arun Banskota, President and Chief Executive Officer of the Corporation, certify, pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002, that to my knowledge:

(1) The Report fully complies with the requirements of Section 13(a) or 15(d) of the Securities Exchange Act of 1934, as amended; and

(2) The information contained in the Report fairly presents, in all material respects, the financial condition and results of operations of the Corporation.

Date: March 21, 2023

By:

/s/ Arun Banskota

Name:

Arun Banskota

Title:

President and Chief Executive Officer

Exhibit 99.8

CERTIFICATION PURSUANT TO

18 U.S.C. SECTION 1350,

AS ADOPTED PURSUANT TO

SECTION 906 OF THE SARBANES-OXLEY ACT OF 2002

In connection with the Annual Report of Algonquin Power & Utilities Corp. (the “Corporation”) on Form 40-F for the year ended December 31, 2022 as filed with the Securities and Exchange Commission on the date hereof (the “Report”), I, Darren Myers, Chief Financial Officer of the Corporation, certify, pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002, that to my knowledge:

(1) The Report fully complies with the requirements of Section 13(a) or 15(d) of the Securities Exchange Act of 1934, as amended; and

(2) The information contained in the Report fairly presents, in all material respects, the financial condition and results of operations of the Corporation.

Date: March 21, 2023

By:

/s/ Darren Myers

Name:

Darren Myers

Title:

Chief Financial Officer

v3.23.1

Cover Page - shares
12 Months Ended

Dec. 31, 2022

Dec. 31, 2021

Dec. 31, 2020

Entity Information [Line Items]

Document Type 40-F/A

Document Registration Statement false

Document Annual Report true

Document Period End Date Dec. 31, 2022

Current Fiscal Year End Date --12-31

Entity File Number 001-37946

Entity Registrant Name ALGONQUIN POWER & UTILITIES CORP.

Entity Incorporation, State or Country Code Z4

Entity Address, Address Line One 354 Davis Road

Entity Address, City or Town Oakville

Entity Address, State or Province ON

Entity Address, Postal Zip Code L6J 2X1

Entity Address, Country CA

City Area Code 905

Local Phone Number 465-4500

Annual Information Form true

Audited Annual Financial Statements true

Entity Common Stock, Shares Outstanding 683,614,803 671,960,276 597,142,219

Entity Current Reporting Status Yes

Entity Interactive Data Current Yes

Entity Emerging Growth Company false

ICFR Auditor Attestation Flag true

Entity Central Index Key 0001174169

Amendment Flag false

Document Fiscal Period Focus FY

Document Fiscal Year Focus 2022

6.875% Fixed-to-Floating Subordinated Notes - Series 2018-A due October 17, 2078

Entity Information [Line Items]

Title of 12(b) Security 6.875% Fixed-to-Floating Subordinated Notes - Series 2018-A due October 17, 2078

Trading Symbol AQNA

Security Exchange Name NYSE

6.20% Fixed-to-Floating Subordinated Notes - Series 2019-A due July 1, 2079

Entity Information [Line Items]

Title of 12(b) Security 6.20% Fixed-to-Floating Subordinated Notes - Series 2019-A due July 1, 2079

Trading Symbol AQNB

Security Exchange Name NYSE

Common shares

Entity Information [Line Items]

Title of 12(b) Security Common shares, no par value

Trading Symbol AQN

Security Exchange Name NYSE

Corporate Units

Entity Information [Line Items]

Title of 12(b) Security Corporate Units

Trading Symbol AQNU

Security Exchange Name NYSE

Rights to Purchase One Common Share of the Company

Entity Information [Line Items]

Title of 12(b) Security Rights to Purchase One Common Share of the Company

Trading Symbol N/A

Security Exchange Name NYSE

Business Contact

Entity Information [Line Items]

Entity Address, Address Line One 111 Eighth Avenue

Entity Address, City or Town New York

Entity Address, State or Province NY

Entity Address, Postal Zip Code 10011

City Area Code 212

Local Phone Number 894-8940

Contact Personnel Name CT Corporation System

v3.23.1

Audit Information
12 Months Ended

Dec. 31, 2022

Audit Information [Abstract]

Auditor Name Ernst & Young LLP

Auditor Location Toronto, Canada

Auditor Firm ID 1263

v3.23.1

Consolidated Statements of Operations - USD ($)
$ in Thousands
12 Months Ended

Dec. 31, 2022

Dec. 31, 2021

Revenue

Other revenue $ 2,765,155 $ 2,274,142

Expenses

Administrative expenses 80,232 66,726

Depreciation and amortization 455,520 402,963

Asset impairment charge (note 5) 159,568 0

Loss on foreign exchange 13,833 4,371

Costs and expenses, total 2,427,138 1,890,103

Gain on sale of renewable assets (notes 3(a) and 16(c)) 64,028 29,063

Operating income (loss) 402,045 413,102

Interest expense (278,574) (209,554)

Fair value change, income (loss) and impairment charge on long-term investments (note 8) (465,206) (26,457)

Other net losses (note 19) (21,391) (22,949)

Pension and other post-employment non-service costs (note 10) (10,950) (16,313)

Gain on derivative financial instruments (note 24(b)(iv)) 4,408 4,403

Nonoperating income (expense) (771,713) (270,870)

Income (loss) before income taxes (369,668) 142,232

Income tax recovery (expense) (note 18)

Current (7,843) (7,237)

Deferred 69,356 50,662

Income tax expense 61,513 43,425

Net earnings (loss) (308,155) 185,657

Non-controlling interests 111,323 89,637

Non-controlling interests held by related party (15,157) (10,435)

Net effect of non-controlling interests 96,166 79,202

Net earnings (loss) attributable to shareholders of Algonquin Power & Utilities Corp. (211,989) 264,859

Preferred shares, Series A and preferred shares, Series D dividend (note 15) 8,720 9,003

Net earnings (loss) attributable to common shareholders of Algonquin Power & Utilities Corp. $ (220,709) $ 255,856

Basic net earnings (loss) per share (USD per share) $ (0.33) $ 0.41

Diluted net earnings (loss) per share (USD per share) $ (0.33) $ 0.41

Regulated electricity distribution

Revenue

Other revenue $ 1,277,409 $ 1,183,399

Expenses

Expenses 465,570 475,764

Regulated natural gas distribution

Revenue

Other revenue 686,744 525,897

Expenses

Expenses 340,792 194,174

Regulated water reclamation and distribution

Revenue

Other revenue 364,383 234,875

Expenses

Expenses 18,308 12,664

Non-regulated energy sales

Revenue

Other revenue 350,939 256,633

Expenses

Expenses 41,826 31,313

Other revenue

Revenue

Other revenue 85,680 73,338

Operating expenses

Expenses

Expenses $ 851,489 $ 702,128

v3.23.1

Consolidated Statements of Comprehensive Income - USD ($)
$ in Thousands
12 Months Ended

Dec. 31, 2022

Dec. 31, 2021

Statement of Comprehensive Income [Abstract]

Net earnings (loss) $ (308,155) $ 185,657

Other comprehensive income (loss) (“OCI”):

Foreign currency translation adjustment, net of tax expense of $2,423 and recovery of $3,219, respectively (notes 24(b)(iii) and 24(b)(iv)) (23,502) (30,270)

Change in fair value of cash flow hedges, net of tax expense of $20,644 and recovery of $22,077, respectively (note 24(b)(ii)) (94,295) (54,331)

Change in pension and other post-employment benefits, net of tax expense of $8,330 and $9,176, respectively (note 10) 27,761 42,051

OCI, net of tax (90,036) (42,550)

Comprehensive income (loss) (398,191) 143,107

Comprehensive loss attributable to the non-controlling interests (97,816) (78,953)

Comprehensive income (loss) attributable to shareholders of Algonquin Power & Utilities Corp. $ (300,375) $ 222,060

v3.23.1

Consolidated Statements of Comprehensive Income (Parenthetical) - USD ($)
$ in Thousands
12 Months Ended

Dec. 31, 2022

Dec. 31, 2021

Statement of Comprehensive Income [Abstract]

Foreign currency translation adjustment, net of tax (recovery) and expense $ 2,423 $ (3,219)

Change in fair value of cash flow hedges, net of tax (recovery) and expense 20,644 (22,077)

Change in unrealized pension and other post-employment expense, net of tax expense and (recovery) $ (8,330) $ 9,176

v3.23.1

Consolidated Balance Sheets - USD ($)
$ in Thousands

Dec. 31, 2022

Dec. 31, 2021

Current assets:

Cash and cash equivalents $ 57,623 $ 125,157

Trade and other receivables, net (note 4) 528,057 403,426

Fuel and natural gas in storage 95,350 74,209

Supplies and consumables inventory 129,571 103,552

Regulatory assets (note 7) 190,393 158,212

Prepaid expenses 58,653 54,548

Derivative instruments (note 24) 12,270 3,486

Other assets (note 11) 22,564 16,153

Assets, current, total 1,094,481 938,743

Property, plant and equipment, net (note 5) 11,944,885 11,042,446

Intangible assets, net (note 6) 96,683 105,116

Goodwill (note 6) 1,320,579 1,201,244

Regulatory assets (note 7) 1,081,108 1,009,413

Long-term investments (note 8)

Investments carried at fair value 1,344,207 1,848,456

Other long-term investments 462,325 495,826

Derivative instruments (note 24) 71,630 17,136

Deferred income taxes (note 18) 84,416 31,595

Other assets (note 11) 127,299 107,528

Assets 17,627,613 16,797,503

Current liabilities:

Accounts payable 186,080 185,291

Accrued liabilities 555,792 428,733

Dividends payable (note 15) 125,655 114,544

Regulatory liabilities (note 7) 69,865 65,809

Long-term debt (note 9) 423,274 356,397

Other long-term liabilities (note 12) 134,212 167,908

Derivative instruments (note 24) 32,491 38,569

Other liabilities 7,091 7,461

Liabilities, current, total 1,534,460 1,364,712

Long-term debt (note 9) 7,088,743 5,854,978

Regulatory liabilities (note 7) 558,317 510,380

Deferred income taxes (note 18) 565,639 530,187

Derivative instruments (note 24) 137,830 81,676

Pension and other post-employment benefits obligation (note 10) 125,579 238,054

Other long-term liabilities (note 12) 461,230 515,911

Liabilities, noncurrent, total 8,937,338 7,731,186

Redeemable non-controlling interests (note 17)

Redeemable non-controlling interest, held by related party 307,856 306,537

Redeemable non-controlling interests 11,520 12,989

Redeemable non-controlling interests, total 319,376 319,526

Equity:

Preferred shares 184,299 184,299

Common shares (note 13(a)) 6,183,943 6,032,792

Additional paid-in capital 9,413 2,007

Deficit (997,945) (288,424)

Accumulated other comprehensive loss (“AOCI”) (note 14) (160,063) (71,677)

Total equity attributable to shareholders of Algonquin Power & Utilities Corp. 5,219,647 5,858,997

Non-controlling interests (note 17)

Non-controlling interests - tax equity partnership units 1,225,608 1,377,117

Other non-controlling interests 333,362 64,807

Non-controlling interest, held by related party 57,822 81,158

Non-controlling interests, total 1,616,792 1,523,082

Total equity 6,836,439 7,382,079

Commitments and contingencies (note 22)

Liabilities and equity, total $ 17,627,613 $ 16,797,503

v3.23.1

Consolidated Statements of Cash Flows - USD ($)
$ in Thousands
12 Months Ended

Dec. 31, 2022

Dec. 31, 2021

Operating activities

Net earnings (loss) $ (308,155) $ 185,657

Adjustments and items not affecting cash:

Depreciation and amortization 455,520 402,963

Deferred taxes (69,356) (50,662)

Initial value and unrealized loss (gain) on derivative financial instruments 2,462 (5,609)

Share-based compensation 10,920 8,395

Cost of equity funds used for construction purposes (1,896) (637)

Change in value of investments carried at fair value 499,125 122,419

Pension and post-employment expense lower than contributions (15,329) (14,146)

Distributions received from equity investments, net of income 23,829 29,818

Impairment of assets 235,478 0

Other 8,116 1,290

Net change in non-cash operating items (note 23) (221,618) (522,022)

Net cash provided by (used in) operating activities, total 619,096 157,466

Financing activities

Increase in long-term debt 16,825,796 12,834,047

Repayments of long-term debt (15,461,078) (12,895,091)

Issuance of common shares, net of costs 43,546 985,619

Cash dividends on common shares (378,597) (307,115)

Dividends on preferred shares (8,720) (9,003)

Contributions from non-controlling interests and redeemable non-controlling interests 272,515 1,125,548

Production-based cash contributions from non-controlling interest 6,182 4,832

Distributions to non-controlling interests, related party (note 17) (34,816) (28,007)

Distributions to non-controlling interests (43,919) (12,830)

Payments upon settlement of derivatives (28,913) (33,782)

Shares surrendered to fund withholding taxes on exercised share options (4,667) (3,372)

Acquisition of non-controlling interest (1,580) 0

Increase in other long-term liabilities 19,324 62,000

Decrease in other long-term liabilities (94,837) (49,130)

Net cash provided by (used in) financing activities, total 1,110,236 1,673,716

Investing activities

Additions to property, plant and equipment and intangible assets (1,089,024) (1,345,045)

Increase in long-term investments (221,281) (622,320)

Acquisitions of operating entities (note 3(c)) (632,797) 0

Increase in other assets (26,527) (43,306)

Receipt of principal on development loans receivable 178,300 206,319

Decrease in long-term investments 2,920 220

Other proceeds 0 6,023

Net cash provided by (used in) investing activities, total (1,788,409) (1,798,109)

Effect of exchange rate differences on cash and restricted cash (1,127) (1,702)

Increase (decrease) in cash, cash equivalents and restricted cash (60,204) 31,371

Cash, cash equivalents and restricted cash, beginning of year 161,389 130,018

Cash, cash equivalents and restricted cash, end of year 101,185 161,389

Supplemental disclosure of cash flow information:

Cash paid during the year for interest expense 272,734 219,025

Cash paid during the year for income taxes 10,962 5,019

Cash received during the year for distributions from equity investments 112,951 112,309

Non-cash financing and investing activities:

Property, plant and equipment acquisitions in accruals 120,819 103,427

Issuance of common shares under dividend reinvestment plan and share-based compensation plans 112,918 108,586

Property, plant and equipment, intangible assets and accrued liabilities in exchange of note receivable $ 90,700 $ 90,821

v3.23.1

Notes to the Consolidated Financial Statements
12 Months Ended

Dec. 31, 2022

Organization, Consolidation and Presentation of Financial Statements [Abstract]

Notes to the Consolidated Financial Statements Algonquin Power & Utilities Corp. (“AQN” or the “Company”) is an incorporated entity under the Canada Business Corporations Act. AQN's operations are organized across two primary business units consisting of the Regulated Services Group and the Renewable Energy Group. The Regulated Services Group owns and operates a portfolio of regulated electric, water distribution and wastewater collection, and natural gas utility systems and transmission operations in the United States, Canada, Bermuda and Chile; the Renewable Energy Group owns and operates, or has investments in, a diversified portfolio of non-regulated renewable and thermal energy generation assets.

v3.23.1

Significant accounting policies
12 Months Ended

Dec. 31, 2022

Accounting Policies [Abstract]

Significant accounting policies Significant accounting policies
(a)Basis of preparation
The accompanying consolidated financial statements and notes have been prepared in accordance with generally accepted accounting principles in the United States (“U.S. GAAP”) and follow disclosure required under Regulation S-X provided by the U.S. Securities and Exchange Commission.
(b)Basis of consolidation
The accompanying consolidated financial statements of AQN include the accounts of AQN, its wholly owned subsidiaries and variable interest entities (“VIEs”) where the Company is the primary beneficiary (note 1(m)). Intercompany transactions and balances have been eliminated. Interests in subsidiaries owned by third parties are included in non-controlling interests (note 1(s)).
(c)Business combinations, intangible assets and goodwill
The Company accounts for acquisitions of entities or assets that meet the definition of a business as business combinations. Business combinations are accounted for using the acquisition method. Assets acquired and liabilities assumed are measured at their fair value at the acquisition date, except for deferred income taxes, which are accounted for as described in note 1(v). Acquisition costs are expensed in the period incurred. When the set of activities does not represent a business, the transaction is accounted for as an asset acquisition and includes acquisition costs.
Intangible assets acquired are recognized separately at fair value if they arise from contractual or other legal rights or are separable. Power sales contracts are amortized on a straight-line basis over the remaining term of the contract ranging from 6 to 25 years from the date of acquisition. Interconnection agreements are amortized on a straight-line basis over their estimated life of 40 years. The majority of the Company's customer relationships are amortized on a straight-line basis over their estimated lives of 25 to 40 years. Certain customer relationships and water rights in Chile as well as brand names are considered indefinite-lived intangibles and are not amortized, but assessed annually for indicators of impairment. Miscellaneous intangibles include renewable energy credits that are purchased by the Company's electric utilities to satisfy renewable portfolio standard obligations. These intangibles are not amortized but are derecognized when remitted to the respective state authority to satisfy the compliance obligation.
Goodwill represents the excess of the purchase price of an acquired business over the fair value of the net assets acquired. Goodwill is generally not included in the rate base on which regulated utilities are allowed to earn a return and is not amortized.
As at September 30 of each year, the Company assesses qualitative and quantitative factors to determine whether it is more likely than not that the fair value of a reporting unit to which goodwill is attributed is less than its carrying amount. If it is more likely than not that a reporting unit’s fair value is less than its carrying amount or if a quantitative assessment is elected, the Company calculates the fair value of the reporting unit. If the carrying amount of the reporting unit as a whole exceeds the reporting unit’s fair value, an impairment charge is recorded in an amount of that excess, limited to the total amount of goodwill allocated to that reporting unit. Goodwill is tested for impairment between annual tests if an event occurs or circumstances change that would more likely than not reduce the fair value of a reporting unit below its carrying amount.
1.Significant accounting policies (continued)
(d)Accounting for rate regulated operations
The operating companies within the Regulated Services Group are subject to rate regulation generally overseen by the regulatory authorities of the jurisdictions in which they operate (the “Regulator”). The Regulator provides the final determination of the rates charged to customers. AQN’s regulated operating companies are accounted for under the principles of U.S. Financial Accounting Standards Board (“FASB”) ASC Topic 980, Regulated Operations (“ASC 980”) except for AQN's Chilean operating company, Empresa de Servicios de Los Lagos S.A. (“ESSAL”), which was acquired in October 2020. The rates that are approved under the Chilean regulatory framework are designed to recover the costs of service of a model water utility. Because the rates are not designed to recover ESSAL's specific costs of service, the utility does not meet the criteria to follow the accounting guidance under ASC 980.
Under ASC 980, regulatory assets and liabilities are recorded to the extent that they represent probable future revenue or expenses associated with certain charges or credits that will be recovered from or refunded to customers through the rate making process. Included in note 7, “Regulatory matters”, are details of regulatory assets and liabilities, and their current regulatory treatment.
In the event the Company determines that its net regulatory assets are not probable of recovery, it would no longer apply the principles of the current accounting guidance for rate regulated enterprises and would be required to record an after-tax, non-cash charge or credit against earnings for any remaining regulatory assets or liabilities. The impact could be material to the Company’s reported financial condition and results of operations.
The U.S. electric, gas and water utilities’ accounts are maintained in accordance with the Uniform System of Accounts prescribed by the Federal Energy Regulatory Commission (“FERC”), the applicable Regulator(s) and National Association of Regulatory Utility Commissioners in the United States. The New Brunswick Gas accounts are maintained in accordance with the New Brunswick Gas Distribution Act Uniform Accounting Regulation.
(e)Cash and cash equivalents
Cash and cash equivalents include all highly liquid instruments with an original maturity of three months or less.
(f)Restricted cash
Restricted cash represents reserves and amounts set aside pursuant to requirements of various debt agreements, deposits to be returned back to customers, and certain requirements related to generation and transmission operations. Cash reserves segregated from AQN’s cash balances are maintained in accounts administered by a separate agent and disclosed separately as restricted cash in these consolidated financial statements. AQN cannot access restricted cash without the prior authorization of parties not related to AQN.
(g)Accounts receivable
Trade accounts receivable are recorded at the invoiced amount and do not bear interest. The Company maintains an allowance for doubtful accounts for estimated losses inherent in its accounts receivable portfolio. In establishing the required allowance, management considers historical losses adjusted to take into account current market conditions and customers’ financial condition, the amount of receivables in dispute, future economic conditions and outlook, and the receivables aging and current payment patterns. Account balances are charged against the allowance after all means of collection have been exhausted and the potential for recovery is considered remote. The Company does not have any off-balance sheet credit exposure related to its customers.
1.Significant accounting policies (continued)
(h)Fuel and natural gas in storage
Fuel and natural gas in storage is reflected at weighted average cost or first-in-first-out as required by regulators and represents fuel, natural gas and liquefied natural gas that will be utilized in the ordinary course of business of the gas utilities and some generating facilities. Existing rate orders and other contracts allow the Company to pass through the cost of gas purchased directly to the customers along with any applicable authorized delivery surcharge adjustments (note 7(a)). Accordingly, the net realizable value of fuel and gas in storage does not fall below the cost to the Company.
(i)Supplies and consumables inventory
Supplies and consumables inventory (other than capital spares and rotatable spares, which are included in property, plant and equipment) are charged to inventory when purchased and then capitalized to plant or expensed, as appropriate, when installed, used or upon becoming obsolete. These items are stated at the lower of cost and net realizable value. Through rate orders and the regulatory environment, capitalized construction jobs are recovered through rate base and repair and maintenance expenses are recovered through a cost of service calculation. Accordingly, the cost usually reflects the net realizable value.
(j)Property, plant and equipment
Property, plant and equipment are recorded at cost. Capitalization of development projects begins when management with the relevant authority has authorized and committed to the funding of a project and it is probable that costs will be realized through the use of the asset or ultimate construction and operation of a facility. Project development costs for rate regulated entities, including expenditures for preliminary surveys, plans, investigations, environmental studies, regulatory applications and other costs incurred for the purpose of determining the feasibility of capital expansion projects, are capitalized either as regulatory assets or property, plant and equipment when it is determined that recovery of such costs through regulated revenue of the completed project is probable.
The costs of acquiring or constructing property, plant and equipment include the following: materials, labour, contractor and professional services, construction overhead directly attributable to the capital project (where applicable), interest for non-regulated property and allowance for funds used during construction (“AFUDC”) for regulated property. Where possible, individual components are recorded and depreciated separately in the books and records of the Company. Plant and equipment under finance leases are initially recorded at cost determined as the present value of lease payments to be made over the lease term.
AFUDC represents the cost of borrowed funds and a return on other funds. Under ASC 980, an allowance for funds used during construction projects that are included in rate base is capitalized. This allowance is designed to enable a utility to capitalize financing costs during periods of construction of property subject to rate regulation. For operations that do not apply regulatory accounting, interest related only to debt is capitalized as a cost of construction in accordance with ASC 835, Interest. The interest capitalized that relates to debt reduces interest expense on the consolidated statements of operations. The AFUDC capitalized that relates to equity funds is recorded as interest and other income under income from long-term investments on the consolidated statements of operations.
Improvements that increase or prolong the service life or capacity of an asset are capitalized. Costs incurred for major expenditures or overhauls that occur at regular intervals over the life of an asset are capitalized and depreciated over the related interval. Maintenance and repair costs are expensed as incurred. Grants related to capital expenditures are recorded as a reduction to the cost of assets and are amortized at the rate of the related asset as a reduction to depreciation expense. Grants related to operating expenses such as maintenance and repairs costs are recorded as a reduction of the related expense. Contributions in aid of construction represent amounts contributed by customers, governments and developers to assist with the funding of some or all of the cost of utility capital assets. They also include amounts initially recorded as advances in aid of construction (note 12(c)) once the advance repayment period has expired. These contributions are recorded as a reduction in the cost of utility assets and are amortized at the rate of the related asset as a reduction to depreciation expense.
1.Significant accounting policies (continued)
(j)Property, plant and equipment (continued)

The Company’s depreciation is based on the estimated useful lives of the depreciable assets in each category and is determined using the straight-line method with the exception of certain wind assets, as described below. The ranges of estimated useful lives and the weighted average useful lives are summarized below:
Range of useful lives Weighted average useful lives
2022 2021 2022 2021
Generation
3-60
3-60
33 33
Distribution
1-100
1-100
39 40
Equipment
5-54
5-50
11 11
The Company uses the unit-of-production method for certain components of its wind generating facilities where the useful life of the component is directly related to the amount of production. The benefits of components subject to wear and tear from the power generation process are best reflected through the unit-of-production method. The Company generally uses wind studies prepared by third parties to estimate the total expected production of each component.
In accordance with regulator-approved accounting policies, when depreciable property, plant and equipment of the Regulated Services Group are replaced or retired, the original cost plus any removal costs incurred (net of salvage) are charged to accumulated depreciation with no gain or loss reflected in results of operations. Gains and losses will be charged to results of operations in the future through adjustments to depreciation expense. In the absence of regulator-approved accounting policies, gains and losses on the disposition of property, plant and equipment are charged to earnings as incurred.
(k)Commonly owned facilities
The Regulated Services Group owns undivided interests in three electric generating facilities with ownership interest ranging from 7.52% to 60%, with a corresponding share of capacity and generation from the facility used to serve certain of its utility customers. The Company's investment in the undivided interest is recorded as plant in service and recovered through rate base. Commonly owned facilities represent cost of $559,630 (2021 - $557,954) and accumulated depreciation of $75,820 (2021 - $59,857). The Company's share of operating costs is recognized in operating, maintenance and fuel expenditures excluding depreciation expense. Total expenditures incurred on these facilities for the year ended December 31, 2022 were $110,268 (2021 - $143,255).
(l)Impairment of long-lived assets
AQN reviews property, plant and equipment and finite-life intangible assets for impairment whenever events or changes in circumstances indicate the carrying amount may not be recoverable.
As at September 30 of each year, the Company assesses qualitative factors to determine whether it is more likely than not that the indefinite-lived intangible is impaired. If it is more likely than not that the indefinite-lived intangible asset is impaired, the Company calculates the fair value of the intangible asset. If the carrying value of the intangible asset exceeds its fair value, the Company recognizes an impairment loss in an amount equal to that excess. Indefinite-life intangibles are tested for impairment between annual tests if an event occurs or circumstances change that would more likely than not reduces the fair value below its carrying amount.
Recoverability of assets expected to be held and used is measured by comparing the carrying amount of an asset to undiscounted expected future cash flows. If the carrying amount exceeds the recoverable amount, the asset is written down to its fair value. During the fourth quarter of 2022, the Company recorded an impairment charge of $159,568 to reduce the carrying value of the Senate Wind Facility and other smaller assets from $259,942 to $100,374 (note 5).
1.Significant accounting policies (continued)
(m)Variable interest entities
The Company performs analyses to assess whether its operations and investments represent VIEs. To identify potential VIEs, management reviews contracts under leases, long-term purchase power agreements and jointly owned facilities. VIEs for which the Company is deemed the primary beneficiary are consolidated. In circumstances where AQN is not deemed the primary beneficiary, the VIE is not consolidated (note 8).
The Company has equity and notes receivable interests in two power generating facilities. AQN has determined that these entities are considered VIEs mainly based on total equity at risk not being sufficient to permit the legal entity to finance its activities without additional subordinated financial support. The key decisions that affect the generating facilities’ economic performance relate to siting, permitting, technology, construction, operations and maintenance and financing. As AQN has both the power to direct the activities of the entities that most significantly impact its economic performance and the right to receive benefits or the obligation to absorb losses of the entities that could potentially be significant to the entities, the Company is considered the primary beneficiary.
Total net book value of assets and long-term debt of these facilities amounts to $57,241 (2021 - $59,877) and $15,024 (2021 - 18,344), respectively. The financial performance of these entities reflected on the consolidated statements of operations includes non-regulated energy sales of $19,752 (2021 - 16,772), operating expenses and amortization of $5,834 (2021 - $5,410) and interest expense of $1,723 (2021 - $2,055).
(n)Long-term investments and notes receivable
Investments in which AQN has significant influence but not control are either accounted for using the equity method or at fair value. Equity-method investments are initially measured at cost including transaction costs and interest when applicable. AQN records its share in the income or loss of its equity-method investees in income from long-term investments in the consolidated statements of operations. AQN records in the consolidated statements of operations the fluctuations in the fair value of its investees held at fair value and dividend income when it is declared by the investee.
Notes receivable are financial assets with fixed or determined payments that are not quoted in an active market. Notes receivable are initially recorded at cost, which is generally face value. Subsequent to acquisition, the notes receivable are recorded at amortized cost using the effective interest method. The Company holds these notes receivable as long-term investments and does not intend to sell these instruments prior to maturity. Interest from long-term investments is recorded as earned and when collectability of both the interest and principal are reasonably assured.
If a loss in value of a long-term investment is considered other than temporary, an allowance for impairment on the investment is recorded for the amount of that loss. An allowance on notes receivable is recorded in order to present the net amount expected to be collected on the receivable. This allowance reflects the risk of loss over the remaining contractual life of the asset, taking into consideration historical experience, current conditions, and reasonable and supportable forecasts of future economic conditions. The impairment is measured based on the present value of expected future cash flows discounted at the note’s effective interest rate. During the fourth quarter of 2022, the Renewable Energy Group recorded an impairment charge of $75,910 to reduce the carrying value of its equity investment in the Texas Coastal Wind Facilities (as defined herein) from $282,726 to 206,816 (note 8(c)).
1.Significant accounting policies (continued)
(o)Pension and other post-employment plans
The Company has established defined contribution pension plans, defined benefit pension plans, other post-employment benefit (“OPEB”) plans, and supplemental retirement program (“SERP”) plans for its various employee groups. Employer contributions to the defined contribution pension plans are expensed as employees render service. The Company recognizes the funded status of its defined benefit pension plans, OPEB and SERP plans on the consolidated balance sheets. The Company’s expense and liabilities are determined by actuarial valuations, using assumptions that are evaluated annually as of December 31, including discount rates, mortality, assumed rates of return, compensation increases, turnover rates and healthcare cost trend rates. The impact of modifications to those assumptions and modifications to prior services are recorded as actuarial gains and losses in accumulated other comprehensive income (“AOCI”) and amortized to net periodic cost over future periods using the corridor method. When settlements of the Company's pension plans occur, the Company recognizes associated gains or losses immediately in earnings if the cost of all settlements during the year is greater than the sum of the service cost and interest cost components of the pension plan for the year. The amount recognized is a pro rata portion of the gains and losses in AOCI equal to the percentage reduction in the projected benefit obligation as a result of the settlement.
The costs of the Company’s pension for employees are expensed over the periods during which employees render service and the service costs are recognized as part of administrative expenses in the consolidated statements of operations. The components of net periodic benefit cost other than the service cost component are included in other net losses in the consolidated statements of operations.
(p)Asset retirement obligations
The Company recognizes a liability for asset retirement obligations based on the fair value of the liability when incurred, which is generally upon acquisition, during construction or through the normal operation of the asset. Concurrently, the Company also capitalizes an asset retirement cost, equal to the estimated fair value of the asset retirement obligation, by increasing the carrying value of the related long-lived asset. The asset retirement costs are depreciated over the asset’s estimated useful life and are included in depreciation and amortization expense on the consolidated statements of operations. Increases in the asset retirement obligation resulting from the passage of time are recorded as accretion of asset retirement obligation in the consolidated statements of operations. Actual expenditures incurred are charged against the obligation.
(q)Leases
The Company accounts for leases in accordance with ASC Topic 842, Leases. The Company leases land, buildings, vehicles, rail cars, and office equipment for use in its day-to-day operations. The Company has options to extend the lease term of many of its lease agreements, with renewal periods ranging from one to five years. As at the consolidated balance sheet date, the Company is not reasonably certain that these renewal options will be exercised.
The Renewable Energy Group enters into land easement agreements for the operation of its generation facilities. In assessing whether these contracts contain leases, the Company considers whether it has exclusive use of the land. In the majority of situations, the landowner or grantor of the easement still has full access to the land and can use the land in any capacity, as long as it does not interfere with the Company’s operations. Therefore, these land easement agreements do not contain leases. For land easement agreements that provide exclusive access to and use of the land, these agreements meet the definition of a lease and are within the scope of ASC 842.
The right-of-use assets are included in property, plant and equipment while lease liabilities are included in other liabilities on the consolidated balance sheets. The discount rates used in the measurement of the Company's right-of-use assets and liabilities are the discount rates at the date of lease inception. The Company's lease balances as at December 31, 2022 and its expected lease payments for the next five years and thereafter are not significant.
1.Significant accounting policies (continued)
(r)Share-based compensation
The Company has several share-based compensation plans: a share option plan; an employee share purchase plan (“ESPP”); a deferred share unit (“DSU”) plan; and a restricted share unit (“RSU”) and performance share unit (“PSU”) plan. Equity-classified awards are measured at the grant date fair value of the award. The Company estimates grant date fair value of options using the Black-Scholes option pricing model. The fair value is recognized over the vesting period of the award granted, adjusted for estimated forfeitures. The compensation cost is recorded as administrative expenses in the consolidated statements of operations and additional paid-in capital in equity. Additional paid-in capital is reduced as the awards are exercised, and the amount initially recorded in additional paid-in capital is credited to common shares.
(s)Non-controlling interests
Non-controlling interests represent the portion of equity ownership in subsidiaries that is not attributable to the equity holders of AQN. Non-controlling interests are initially recorded at fair value and subsequently adjusted for the proportionate share of earnings and other comprehensive income (“OCI”) attributable to the non-controlling interests and any dividends or distributions paid to the non-controlling interests.
If a transaction results in the acquisition of all, or part, of a non-controlling interest in a consolidated subsidiary, the acquisition of the non-controlling interest is accounted for as an equity transaction. No gain or loss is recognized in net earnings or comprehensive income as a result of changes in the non-controlling interest, unless a change results in the loss of control by the Company.
Certain of the Company’s U.S. based wind and solar businesses are organized as limited liability corporations (“LLCs”) and partnerships and have non-controlling membership equity investors (“tax equity partnership units”, or “Tax Equity Investors”), which are entitled to allocations of earnings, tax attributes and cash flows in accordance with contractual agreements. These LLCs and partnership agreements have liquidation rights and priorities that are different from the underlying percentage ownership interests. In those situations, simply applying the percentage ownership interest to U.S. GAAP net income in order to determine earnings or losses would not accurately represent the income allocation and cash flow distributions that will ultimately be received by the investors. As such, the share of earnings attributable to the non-controlling interest holders in these entities is calculated using the Hypothetical Liquidation at Book Value (“HLBV”) method of accounting (note 17).
The HLBV method uses a balance sheet approach. A calculation is prepared at each balance sheet date to
determine the amount that Tax Equity Investors would receive if an equity investment entity were to liquidate all of its assets and distribute that cash to the investors based on the contractually defined liquidation priorities. The difference between the calculated liquidation distribution amounts at the beginning and the end of the reporting period is the Tax Equity Investors' share of the earnings or losses from the investment for that period.
Equity instruments subject to redemption upon the occurrence of uncertain events not solely within AQN’s control are classified as temporary equity and presented as redeemable non-controlling interests on the consolidated balance sheets. The Company records temporary equity at issuance based on cash received less any transaction costs. As needed, the Company reevaluates the classification of its redeemable instruments, as well as the probability of redemption. If the redemption amount is probable or currently redeemable, the Company records the instruments at their redemption value. Increases or decreases in the carrying amount of a redeemable instrument are recorded within deficit. When the redemption feature lapses or other events cause the classification of an equity instrument as temporary equity to be no longer required, the existing carrying amount of the equity instrument is reclassified to permanent equity at the date of the event that caused the reclassification.
(t)Recognition of revenue
Revenue is recognized when control of the promised goods or services is transferred to the Company’s customers in an amount that reflects the consideration the Company expects to be entitled to in exchange for those goods or services.
Refer to note 21, “Segmented information” for details of revenue disaggregation by business units.
1.Significant accounting policies (continued)
(t)Recognition of revenue (continued)
Regulated Services Group revenue
Regulated Services Group revenue derives primarily from the distribution of electricity, water and natural gas.
Revenue related to utility electricity and natural gas sales and distribution is recognized over time as the energy is delivered. At the end of each month, the electricity and natural gas delivered to the customers from the date of their last meter read to the end of the month is estimated and the corresponding unbilled revenue is recorded. These estimates of unbilled revenue and sales are based on the ratio of billable days versus unbilled days, amount of electricity or natural gas procured during that month, historical customer class usage patterns, weather, line loss, unaccounted-for natural gas and current tariffs. Unbilled receivables are typically billed within the next month. Some customers elect to pay their bill on an equal monthly plan.
As a result, in some months cash is received in advance of the delivery of electricity. Deferred revenue is recorded for that amount. The amount of revenue recognized in the period from the balance of deferred revenue is not significant.
Water reclamation and distribution revenue is recognized over time when water is processed or delivered to customers. At the end of each month, the water delivered and wastewater collected from the customers from the date of their last meter read to the end of the month are estimated and the corresponding unbilled revenue is recorded. These estimates of unbilled revenue are based on the ratio of billable days versus unbilled days, amount of water procured and collected during that month, historical customer class usage patterns and current tariffs. Unbilled receivables are typically billed within the next month.
On occasion, a utility is permitted to implement new rates that have not been formally approved by the regulatory commission, which are subject to refund. The Company recognizes revenue based on the interim rate and, if needed, establishes a reserve for amounts that could be refunded based on experience for the jurisdiction in which the rates were implemented.
Revenue for certain of the Company’s regulated utilities is subject to alternative revenue programs approved by their respective regulators. Under these programs, the Company charges approved annual delivery revenue on a systematic basis over the fiscal year. As a result, the difference between delivery revenue calculated based on metered consumption and approved delivery revenue is disclosed as alternative revenue in note 21, “Segmented information” and is recorded as a regulatory asset or liability to reflect future recovery or refund, respectively, from customers (note 7). The amount subsequently billed to customers is recorded as a recovery of the regulatory asset.
Renewable Energy Group revenue
Renewable Energy Group's revenue derives primarily from the sale of electricity, capacity, and renewable energy credits.
Revenue related to the sale of electricity is recognized over time as the electricity is delivered. The electricity represents a single performance obligation that represents a promise to transfer to the customer a series of distinct goods that are substantially the same and that have the same pattern of transfer to the customer.
Revenue related to the sale of capacity is recognized over time as the capacity is provided. The nature of the promise to provide capacity is that of a stand-ready obligation. The capacity is generally expressed in monthly volumes and prices. The capacity represents a single performance obligation that represents a promise to transfer to the customer a series of distinct services that are substantially the same and that have the same pattern of transfer to the customer.
1.Significant accounting policies (continued)
(t)Recognition of revenue (continued)
Renewable Energy Group revenue (continued)
Qualifying renewable energy projects receive renewable energy credits (“RECs”) and solar renewable energy credits (“SRECs”) for the generation and delivery of renewable energy to the power grid. The energy credit certificates represent proof that 1 MW of electricity was generated from an eligible energy source. The RECs and SRECs can be traded and the owner of the RECs or SRECs can claim to have purchased renewable energy. RECs and SRECs are primarily sold under fixed contracts, and revenue for these contracts is recognized at a point in time, upon generation of the associated electricity. Any RECs or SRECs generated above contracted amounts are held in inventory, with the offset recorded as a decrease in operating expenses.
The Company applies the invoicing expedient to the electricity and capacity in the Renewable Energy Group contracts. As such, revenue is recognized at the amount to which the Company has the right to invoice for services performed. Revenue is recorded net of sales taxes.
(u)Foreign currency translation
AQN’s reporting currency is the U.S. dollar. Within these consolidated financial statements, the Company denotes any amounts denominated in Canadian dollars with “C$”, in Chilean pesos with “CLP” and in Chilean Unidad de Fomento with “CLF” immediately prior to the stated amounts.
Effective January 1, 2020, the functional currency of AQN, the non-consolidated parent entity, changed from the Canadian dollar to the U.S. dollar based on a balance of facts taking into consideration its operating, financing and investing activities. As a result of the entity's change of functional currency, changes were made to certain hedging relationships to mitigate the remaining Canadian dollar risk (note 24).
The Company’s Canadian operations have the Canadian dollar as their functional currency since the preponderance of operating, financing and investing transactions are denominated in Canadian dollars. Similarly, the Company's Chilean and Bermudian operations' functional currency is the Chilean peso and the Bermudian dollar, respectively. The financial statements of these operations are translated into U.S. dollars using the current rate method, whereby assets and liabilities are translated at the rate prevailing at the balance sheet date, and revenue and expenses are translated using average rates for the period. Unrealized gains or losses arising as a result of the translation of the financial statements of these entities are reported as a component of OCI and are accumulated in a component of equity on the consolidated balance sheets, and are not recorded in income unless there is a complete or substantially complete sale or liquidation of the investment.
(v)Income taxes
Income taxes are accounted for using the asset and liability method. Deferred tax assets and liabilities are recognized for the future tax consequences attributable to differences between the financial statement carrying amounts of assets and liabilities and their respective tax bases. Deferred tax assets and liabilities are measured using enacted tax rates expected to apply to taxable income in the years in which those temporary differences are expected to be recovered or settled. A valuation allowance is recorded against deferred tax assets to the extent that it is considered more likely than not that the deferred tax asset will not be realized. The effect on deferred tax assets and liabilities of a change in tax rates is recognized in earnings in the period that includes the date of enactment. Investment tax credits for the rate regulated operations are deferred and amortized as a reduction to income tax expense over the estimated useful lives of the properties. Investment tax credits along with other income tax credits in the non-regulated operations are treated as a reduction to income tax expense in the year the credit arises.
The organizational structure of AQN and its subsidiaries is complex and the related tax interpretations, regulations and legislation in the tax jurisdictions in which they operate are continually changing. As a result, there can be tax matters that have uncertain tax positions. The Company recognizes the effect of income tax positions only if those positions are more likely than not of being sustained. Recognized income tax positions are measured at the largest amount that is greater than 50% likely of being realized. Changes in recognition or measurement are reflected in the period in which the change in judgment occurs.
1.Significant accounting policies (continued)
(w)Financial instruments and derivatives
Accounts receivable and notes receivable are measured at amortized cost. Long-term debt and preferred shares, Series C are measured at amortized cost using the effective interest method, adjusted for the amortization or accretion of premiums or discounts.
Transaction costs that are directly attributable to the acquisition of financial assets are accounted for as part of the asset’s carrying value at inception. Transaction costs related to a recognized debt liability are presented in the consolidated balance sheets as a direct deduction from the carrying amount of that debt liability, consistent with debt discounts and premiums. Costs of arranging the Company’s revolving credit facilities and intercompany loans are recorded in other assets. Deferred financing costs, premiums and discounts on long-term debt are amortized using the effective interest method while deferred financing costs relating to the revolving credit facilities and intercompany loans are amortized on a straight-line basis over the term of the respective instrument.
The Company uses derivative financial instruments as one method to manage exposures to fluctuations in exchange rates, interest rates and commodity prices. AQN recognizes all derivative instruments as either assets or liabilities on the consolidated balance sheets at their respective fair values. The fair value recognized on derivative instruments executed with the same counterparty under a master netting arrangement are presented on a gross basis on the consolidated balance sheets. The amounts that could net settle are not significant. The Company applies hedge accounting to some of its financial instruments used to manage its foreign currency risk, interest rate risk and price risk exposures associated with sales of generated electricity.
For derivatives designated in a cash flow hedge relationship, the change in fair value is recognized in OCI.
The amount recognized in AOCI is reclassified to earnings in the same period as the hedged cash flows affect earnings under the same line item in the consolidated statements of operations as the hedged item. If the hedging instrument no longer meets the criteria for hedge accounting, expires or is sold, terminated, exercised, or the designation is revoked, then hedge accounting is discontinued prospectively. The amount remaining in AOCI is transferred to the consolidated statements of operations in the same period that the hedged item affects earnings. If the forecasted transaction is no longer expected to occur, then the balance in AOCI is recognized immediately in earnings.
Foreign currency gain or loss on derivative or financial instruments designated as a hedge of the foreign currency exposure of a net investment in foreign operations that are effective as a hedge is reported in the same manner as the translation adjustment (in OCI) related to the net investment.
The Company’s electric distribution and thermal generation facilities enter into power and natural gas purchase contracts for load serving and generation requirements. These contracts meet the exemption for normal purchase and normal sales and, as such, are not required to be recorded at fair value as derivatives and are accounted for on an accrual basis. Counterparties are evaluated on an ongoing basis for non-performance risk to ensure it does not impact the conclusion with respect to this exemption.
(x)Fair value measurements
The Company utilizes valuation techniques that maximize the use of observable inputs and minimize the use of unobservable inputs to the extent possible. The Company determines fair value based on assumptions that market participants would use in pricing an asset or liability in the principal or most advantageous market. When considering market participant assumptions in fair value measurements, the following fair value hierarchy distinguishes between observable and unobservable inputs, which are categorized in one of the following levels:
•Level 1 Inputs: Unadjusted quoted prices in active markets for identical assets or liabilities accessible to the reporting entity at the measurement date.
•Level 2 Inputs: Other than quoted prices included in level 1, inputs that are observable for the asset or liability, either directly or indirectly, for substantially the full term of the asset or liability.
•Level 3 Inputs: Unobservable inputs for the asset or liability used to measure fair value to the extent that observable inputs are not available, thereby allowing for situations in which there is little, if any, market activity for the asset or liability at the measurement date.
1.Significant accounting policies (continued)
(y)Commitments and contingencies
Liabilities for loss contingencies arising from environmental remediation, claims, assessments, litigation, fines, penalties and other sources are recorded when it is probable that a liability has been incurred and the amount can be reasonably estimated. Legal costs incurred in connection with loss contingencies are expensed as incurred.
(z)Use of estimates
The preparation of financial statements requires management to make estimates and assumptions that affect the reported amounts of assets and liabilities and disclosure of contingent assets and liabilities at the date of these consolidated financial statements and the reported amounts of revenue and expenses during the year. Actual results could differ from those estimates. During the years presented, management has made a number of estimates and valuation assumptions, including the useful lives and recoverability of property, plant and equipment, intangible assets and goodwill; the recoverability of notes receivable and long-term investments; the recoverability of deferred tax assets; assessments of unbilled revenue; pension and OPEB obligations; timing effect of regulated assets and liabilities; contingencies related to environmental matters; the fair value of assets and liabilities acquired in a business combination; and the fair value of financial instruments. These estimates and valuation assumptions are based on present conditions and management’s planned course of action, as well as assumptions about future business and economic conditions. Should the underlying valuation assumptions and estimates change, the recorded amounts could change by a material amount.

v3.23.1

Recently issued accounting pronouncements
12 Months Ended

Dec. 31, 2022

Accounting Standards Update and Change in Accounting Principle [Abstract]

Recently adopted accounting pronouncements Recently issued accounting pronouncements
(a)Recently adopted accounting pronouncements
The Financial Accounting Standards Board (“FASB”) issued ASU 2021-05, Leases (Topic 842): Lessors — Certain Leases with Variable Lease Payments to address concerns relating to day-one losses for sales-type or direct financing leases with variable payments that do not depend on a reference index or rate. The update amends the lease classification requirements for lessors to align them with past practice under Topic 840, Leases. The adoption of this update did not have an impact on the consolidated financial statements.
The FASB issued ASU 2020-06, Debt — Debt with Conversion and Other Options (Subtopic 470-20) and Derivatives and Hedging — Contracts in Entity's Own Equity (Subtopic 815-40): Accounting for Convertible Instruments and Contracts in an Entity's Own Equity to address the complexity associated with accounting for certain financial instruments with characteristics of liabilities and equity. The number of accounting models for convertible debt instruments and convertible preferred stock is being reduced and the guidance has been amended for the derivatives scope exception for contracts in an entity's own equity to reduce form-over-substance-based accounting conclusions. The adoption of this update did not have an impact on the consolidated financial statements.
The FASB issued ASU 2020-04, Reference Rate Reform (Topic 848): Facilitation of the Effects of Reference Rate Reform on Financial Reporting, which provides optional expedients and exceptions to ease the potential burden in accounting for reference rate reform. The amendments apply to contracts, hedging relationships, and other transactions that reference LIBOR or another reference rate expected to be discontinued because of the reference rate reform. The FASB issued updates to Topic 848 in ASU 2022-06 and 2021-01 to clarify that the scope of Topic 848 includes derivatives affected by the discounting transition and extend the relief in Topic 848 to December 31, 2024, respectively. The adoption of this update did not have an impact on the consolidated financial statements.
(b)Recently issued accounting guidance not yet adopted
The FASB issued ASU 2022-04, Liabilities — Supplier Finance Programs (Subtopic 405-50): Disclosure of Supplier Finance Program Obligations, which require that a buyer in a supplier finance program disclose sufficient information about the program to allow a user of financial statements to understand the program’s nature, activity during the period, changes from period to period, and potential magnitude. The amendments in this update are effective for fiscal years beginning after December 15, 2022, including interim periods within those fiscal years, except for the amendment on roll forward information, which is effective for fiscal years beginning after December 15, 2023. Early adoption is permitted. The Company is currently assessing the relevant disclosure.

v3.23.1

Business acquisitions and disposition transactions
12 Months Ended

Dec. 31, 2022

Business Combination and Asset Acquisition [Abstract]

Business acquisitions, development projects and disposition transactions Business acquisitions, development projects and disposition transactions
(a)Partial disposition of renewable assets
On December 29, 2022, the Company closed the sale of ownership interests in a portfolio of operating wind facilities in the United States and Canada. The transaction consisted of the sale of (1) a 49% ownership interest in three operating wind facilities in the United States totalling 551 MW of installed capacity: the Odell Wind Facility in Minnesota, the Deerfield Wind Facility in Michigan and the Sugar Creek Wind Facility in Illinois; and (2) an 80% ownership interest in the operating 175 MW Blue Hill Wind Facility in Saskatchewan. The Company retains control over the U.S. facilities. The Company will continue to oversee day-to-day operations and provide management services to each of the facilities.
The cash proceeds of $277,500 for the U.S. facilities, which continue to be consolidated, were recorded as non-controlling interest (subject to certain potential future post-closing adjustments). The investment in the Blue Hill Wind Facility continues to be recorded as an equity-method investee. Cash proceeds of C$108,610 were received for the Blue Hill Wind Facility (subject to certain potential future post-closing adjustments). A gain on disposition of $62,828 was recognized and included in gain on sale of renewable assets on the consolidated statements of operations.
(b)Pending acquisition of Kentucky Power Company and AEP Kentucky Transmission Company, Inc.
On October 26, 2021, Liberty Utilities Co., an indirect subsidiary of AQN, entered into an agreement (the “Kentucky Acquisition Agreement”) with American Electric Power Company, Inc. (“AEP”) and AEP Transmission Company, LLC to acquire Kentucky Power Company (“Kentucky Power”) and AEP Kentucky Transmission Company, Inc. (“Kentucky TransCo”) for a total purchase price of approximately $2,846,000, including the assumption of approximately $1,221,000 in debt (the “Kentucky Power Transaction”). On September 29, 2022, the parties entered into an amendment to the Kentucky Acquisition Agreement that, among other things, reduces the purchase price by $200,000.
Kentucky Power is a state rate-regulated electricity generation, distribution and transmission utility in 20 eastern Kentucky counties and operating under a cost of service framework. Kentucky TransCo is an electricity transmission business operating in the Kentucky portion of the transmission infrastructure that is part of the Pennsylvania – New Jersey – Maryland regional transmission organization, PJM Interconnection, L.L.C. Kentucky Power and Kentucky TransCo are both regulated by FERC.
Closing of the Kentucky Power Transaction remains subject to the satisfaction or waiver of certain conditions precedent, which include the approval of the Kentucky Power Transaction by FERC and clearance under the Hart-Scott-Rodino Antitrust Improvements Act of 1976 (as the clearance received previously has lapsed). On December 15, 2022, FERC issued an order denying, without prejudice, authorization for the proposed transaction. On February 14, 2023, a new application was filed with FERC for approval of the Kentucky Power Transaction. If the Kentucky Power Transaction has not closed by April 26, 2023, either party may, if certain requirements are met, terminate the Kentucky Acquisition Agreement in accordance with its terms.
(c)Acquisition of New York American Water Company, Inc.
Effective January 1, 2022, the Company completed the acquisition of New York American Water Company, Inc (subsequently renamed Liberty Utilities (New York Water) Corp. (“Liberty NY Water”)). Liberty NY Water is a regulated water and wastewater utility, serving customers in eight counties in southeastern New York.
3.Business acquisitions, development projects and disposition transactions (continued)
(c)Acquisition of New York American Water Company, Inc. (continued)
A purchase price of $609,000 was paid for this acquisition. The acquisition related costs were expensed through the consolidated statement of operations (note 19). The following table summarizes the final allocation of the purchase price to the assets acquired and liabilities assumed when control was obtained.
Working capital $ 4,820
Property, plant and equipment (i) 499,252
Goodwill (ii) 116,254
Regulatory assets (iii) 65,621
Other assets 4,507
Pension and other post-employment benefits (13,402)
Regulatory liabilities (iii) (59,727)
Other liabilities (8,028)
Total net assets acquired $ 609,297
Cash and cash equivalents acquired 49
Total net assets acquired, net of cash and cash equivalents $ 609,248
The determination of the fair value of assets acquired and liabilities assumed is based upon management’s estimates and certain assumptions.
i.Property, plant and equipment, consist of regulated water distribution infrastructure and wastewater collection and treatment facilities. They are amortized in accordance with regulatory requirements over the estimated useful life of the assets using the straight-line method. The weighted average useful life of Liberty NY Water’s assets is 64.74 years.
ii.Goodwill represents the excess of the purchase price over the aggregate fair value of net assets acquired. The contributing factors to the amount recorded as goodwill include future growth, potential synergies, and cost of savings in the delivery of certain shared administrative and other services. Goodwill is reported under the Regulated Services Group.
iii.The Company is subject to regulation by the New York State Public Service Commission (“NYPSC”), which has jurisdiction with respect to rates, service, accounting procedures, acquisitions, and other matters. Under ASC 980, regulatory assets and liabilities are recorded to the extent that they represent probable future revenue or expenses associated with certain charges or credits that will be recovered from or refunded to customers through the rate making process (note 7). As part of the approval of the acquisition of Liberty NY Water, a settlement agreement was approved which requires a full year of ownership prior to the filing of a new rate case. As a result, new rates would not come into effect until 2024.
Liberty NY Water was consolidated upon acquisition. In 2022, Liberty NY Water generated approximately $125,370 in revenue and $21,776 operating income.
(d)Acquisition of Mid-West Wind Facilities
In 2021, the Empire District Electric Company (“Empire Electric System”), a wholly owned subsidiary of the Company, acquired three wind farms generating up to 600 MW of wind energy located in Barton, Dade, Lawrence, and Jasper Counties in Missouri, and in Neosho County, Kansas (collectively, the “Mid-West Wind Facilities”). Up to that point, the Company had held an interest in the construction projects for the North Fork Ridge Wind Facility and the Kings Point Wind Facility. The Empire Electric System paid consideration to third-party developers of $97,760 and obtained control of the facilities. In 2021, subsequent to acquisition, the tax equity investors provided additional funding of $530,880 and third-party construction loans of $789,923 were repaid. The Company accounted for these transactions as asset acquisitions since substantially all of the fair value of gross assets acquired is concentrated in a group of similar identifiable assets.
3.Business acquisitions, development projects and disposition transactions (continued)
(d)Acquisition of Mid-West Wind Facilities (continued)
The following table summarizes the allocation of the aggregate purchase price to the assets acquired and liabilities assumed at the acquisition dates.
Mid-West Wind
Working capital $ (28,630)
Property, plant and equipment 1,141,884
Long-term debt (789,804)
Asset retirement obligation (27,053)
Deferred tax liability (4,566)
Other liabilities (104,129)
Non-controlling interest (tax equity investors) (29,141)
Total net assets acquired 158,561
Cash and cash equivalents 15,860
Net assets acquired, net of cash and cash equivalents $ 142,701
(e)Altavista Solar Facility
Up to April 2021, the Company held a 50% interest in Altavista Solar SponsorCo, LLC, an entity that indirectly owns an 80 MW solar power facility located in Campbell County, Virginia. In April 2021, the Company acquired the remaining 50% interest in Altavista Solar SponsorCo, LLC for $6,735 and as a result, obtained control of the facility. Subsequent to acquisition, the third-party construction loan of $122,024 was repaid. The Company accounted for the transaction as an asset acquisition since substantially all of the fair value of gross assets acquired is concentrated in a group of similar identifiable assets.
The following table summarizes the allocation of the purchase price to the assets acquired and liabilities assumed at the acquisition date of the solar facility.
Altavista Solar
Working capital $ 870
Property, plant and equipment 138,343
Long-term debt (122,024)
Deferred tax liability (421)
Asset retirement obligation (3,332)
Total net assets acquired 13,436
Cash and cash equivalents 33
Net assets acquired, net of cash and cash equivalents $ 13,403
(f)Maverick Creek Wind Facility and Sugar Creek Wind Facility
Up to January 2021, the Company held 50% equity interests in Maverick Creek Wind SponsorCo, LLC and AAGES Sugar Creek Wind, LLC (note 8). The two entities indirectly own 492 MW and 202 MW wind development projects in the state of Texas and Illinois (“Maverick Creek Wind Facility” and “Sugar Creek Wind Facility”), respectively. In January 2021, the Company acquired the remaining 50% interests in Maverick Creek Wind SponsorCo, LLC and AAGES Sugar Creek Wind, LLC for $43,797 in aggregate and obtained control of the facilities. An amount of $18,641 was withheld from the consideration for the acquisition of AAGES Sugar Creek Wind, LLC and remains payable upon the satisfaction of certain conditions. The Company accounted for the transactions as asset acquisitions since substantially all of the fair value of gross assets acquired is concentrated in a group of similar identifiable assets.
3.Business acquisitions, development projects and disposition transactions (continued)
(f)Maverick Creek Wind Facility and Sugar Creek Wind Facility (continued)
The following table summarizes the allocation of the purchase price to the assets acquired and liabilities assumed at the acquisition date of the two wind facilities. The existing loans between the Company and the partnerships of $87,035 were treated as additional consideration incurred to acquire the partnerships.
Maverick Creek and Sugar Creek
Working capital $ (15,557)
Property, plant and equipment 1,062,613
Long-term debt (855,409)
Asset retirement obligation (23,402)
Deferred tax liability (337)
Derivative instruments 7,575
Total net assets acquired 175,483
Cash and cash equivalents 4,241
Net assets acquired, net of cash and cash equivalents $ 171,242
Tax equity investors provided funding of $147,914 and $380,829 to the Sugar Creek Wind Facility and Maverick Creek Wind Facility, respectively, in 2021 and third-party construction loans of $284,829 and $570,578, respectively, were repaid subsequent to the acquisition of the remaining 50% interests in the facilities in 2021. A partial interest in the Sugar Creek Wind Facility was subsequently sold in December 2022 (note 3(a)).

v3.23.1

Accounts receivable
12 Months Ended

Dec. 31, 2022

Accounts, Notes, Loans and Financing Receivable, Gross, Allowance, and Net [Abstract]

Accounts receivable Accounts receivableAccounts receivable as of December 31, 2022 include unbilled revenue of $149,015 (December 31, 2021 - $102,693) from the Company’s regulated utilities. Accounts receivable as of December 31, 2022 are presented net of allowance for doubtful accounts of $24,857 (December 31, 2021 - $19,327).

v3.23.1

Property, plant and equipment
12 Months Ended

Dec. 31, 2022

Property, Plant and Equipment [Abstract]

Property, plant and equipment Property, plant and equipment
Property, plant and equipment consist of the following:
2022
Cost Accumulated depreciation Net book value
Renewable generation facilities $ 4,119,514 $ 1,016,784 $ 3,102,730
Utility plant 8,640,224 990,975 7,649,249
Land 113,153 — 113,153
Equipment 111,707 50,904 60,803
Construction in progress
Generation 196,287 — 196,287
Distribution and transmission 822,663 — 822,663
$ 14,003,548 $ 2,058,663 $ 11,944,885
5.Property, plant and equipment (continued)
2021
Cost Accumulated depreciation Net book value
Renewable generation facilities $ 4,187,197 $ 751,219 $ 3,435,978
Utility plant 7,468,236 780,537 6,687,699
Land 114,821 — 114,821
Equipment 101,971 56,464 45,507
Construction in progress
Generation 148,302 — 148,302
Distribution and transmission 610,139 — 610,139
$ 12,630,666 $ 1,588,220 $ 11,042,446
During the fourth quarter of 2022, the Company concluded that some assets in the Renewable Energy Group may not be recoverable due to declining forecasted energy prices in the Electric Reliability Council of Texas (“ERCOT”) market, mainly affecting the results of the Senate Wind Facility (which began commercial operations in 2012). Accordingly, the Company performed fair value analysis based on the income approach and recorded an impairment charge of $159,568 to reduce the carrying value of the Senate Wind Facility and other smaller assets from $259,942 to $100,374. Changes in assumptions of revenue forecasts, driven by expected production, basis difference and resulting spot prices, projected operating and capital expenditures would affect the estimated fair value.
Renewable generation facilities include cost of $111,192 (2021 - $114,868) and accumulated depreciation of $46,666 (2021 - $46,649) related to facilities under financing lease or owned by consolidated VIEs. Depreciation expense of facilities under finance leases was $1,489 (2021 - $1,716). Utility plant includes cost of $3,076 (2021 - $3,076) and accumulated depreciation of $2,041 (2021 - $1,665) related to assets under finance lease.
Utility plant includes cost of $2,033,391 (2021 - $2,018,039) and accumulated depreciation of $133,644 (2021 - $72,484) related to regulated generation assets.
For the year ended December 31, 2022, contributions received in aid of construction of $1,299 (2021 - $6,376) have been credited to the cost of the assets.
Interest and AFUDC capitalized to the cost of the assets in 2022 and 2021 are as follows:
2022 2021
Interest capitalized on non-regulated property $ 4,762 $ 3,313
AFUDC capitalized on regulated property:
Allowance for borrowed funds 6,040 3,208
Allowance for equity funds 1,901 829
$ 12,703 $ 7,350

v3.23.1

Intangible assets and goodwill
12 Months Ended

Dec. 31, 2022

Goodwill and Intangible Assets Disclosure [Abstract]

Intangible assets and goodwill Intangible assets and goodwill
Intangible assets consist of the following:
2022 Cost Accumulated amortization Net book value
Power sales contracts $ 56,926 $ 42,818 $ 14,108
Customer relationships 77,850 13,709 64,141
Interconnection agreements 10,098 1,851 8,247
Other (a)
10,338 151 10,187
$ 155,212 $ 58,529 $ 96,683
2021 Cost Accumulated amortization Net book value
Power sales contracts $ 58,112 $ 43,118 $ 14,994
Customer relationships 78,140 12,337 65,803
Interconnection agreements 15,072 1,721 13,351
Other (a)
10,968 — 10,968
$ 162,292 $ 57,176 $ 105,116
(a) Other includes brand names, water rights and miscellaneous intangibles
Estimated amortization expense for intangible assets for each of the next year is $2,580 and $2,572 for years two to five.
All goodwill pertains to the Regulated Services Group.
2022 2021
Opening balance $ 1,201,244 $ 1,208,390
Business acquisitions (note 3) 123,751 5,535
Foreign exchange (4,416) (12,681)
Closing balance $ 1,320,579 $ 1,201,244

v3.23.1

Regulatory matters
12 Months Ended

Dec. 31, 2022

Regulated Operations [Abstract]

Regulatory matters Regulatory mattersThe operating companies within the Regulated Services Group are subject to regulation by the respective Regulators of the jurisdictions in which they operate. The respective Regulators have jurisdiction with respect to rate, service, accounting policies, issuance of securities, acquisitions and other matters. Except for ESSAL, these utilities operate under cost-of-service regulation as administered by these authorities. The Company’s regulated utility operating companies are accounted for under the principles of ASC 980, Regulated Operations. Under ASC 980, regulatory assets and liabilities that would not be recorded under U.S. GAAP for non-regulated entities are recorded to the extent that they represent probable future revenue or expenses associated with certain charges or credits that will be recovered from or refunded to customers through the rate setting process.
7.Regulatory matters (continued)
At any given time, the Company can have several regulatory proceedings underway. The financial effects of these proceedings are reflected in the consolidated financial statements based on regulatory approval obtained to the extent that there is a financial impact during the applicable reporting period. The following regulatory proceedings were recently completed:
Utility State, Province or Country Regulatory Proceeding Type Details
BELCO Bermuda General rate review
On March 18, 2022, the Regulatory Authority (“RA”) approved an annual increase of $22,800, for a revenue allowance of $224,056 and $226,160 in revenue for 2022 and 2023, respectively. The RA authorized a rate of return of 7.16%, comprised of a 62% equity and an 8.92% return on equity. The new rates are effective from April 1, 2022. In April, 2022, BELCO filed an appeal in the Supreme Court of Bermuda challenging the decisions made by the RA through the recent Retail Tariff Review.
Empire Electric Missouri General Rate Case (GRC) and Securitization
On April 6, 2022, the Missouri Public Service Commission (the "MPSC") approved an annual base rate increase of $35,516, as well as another $4,000 in revenues associated with the Empire Wind Facilities. The new rates became effective in June 2022.

On January 19, 2022, Empire Electric filed a petition for securitization of the costs associated with the impact of the Midwest Extreme Weather Event. On March 21, 2022, Empire Electric filed a petition for securitization of the costs associated with the retirement of the Asbury generating plant. On August 18, 2022, and September 22, 2022, the MPSC issued and amended, respectively, a Report and Order authorizing Empire Electric to securitize approximately $290,383 in qualified extraordinary costs (Midwest Extreme Weather Event), energy transition costs (Asbury) and upfront financing costs associated with the proposed securitization. The amounts authorized by the securitization order are generally consistent with the costs deferred by the Company in relation to these matters. Empire Electric filed an appeal of the MPSC order on November 10, 2022 (note 7(a) and (b)). Briefing of the case is expected to be completed in April 2023.
7.Regulatory matters (continued)

Utility State, Province or Country Regulatory Proceeding Type Details
Empire Electric Kansas GRC
On May 27, 2021, Empire Electric submitted an abbreviated rate review seeking to recover costs associated with the addition of the Empire Wind Facilities, the retirement of Asbury and non-growth related plant investments since the 2019 rate review. In May 2022, the Commission approved the unanimous partial settlement resolving the rate treatment of the Asbury retirement and the non-wind investments resulting in a base rate decrease of $636, and granted Empire Electric's motion to withdraw its request to recover cost associated with the Empire Wind Facilities. New rates became effective in July 2022.
Empire District Gas Company Missouri GRC
In June 2022, the Commission approved an annual increase of $1,000 in base rate revenues. New rates became effective in August 2022.
Empire Electric Oklahoma GRC
On December 29, 2022 the Commission approved a joint stipulation and agreement filed by the Company and Staff authorizing an annual base rate revenue increase of $5,100.
New Brunswick Gas Canada GRC
On November 22, 2021, New Brunswick Gas filed its 2022 general rate application for a revenue decrease based on the Energy & Utilities Board's recent decision authorizing a capital structure of 45% equity and an ROE of 8.5%. In January 2022, New Brunswick Natural Gas appealed the Energy & Utilities Board's cost of capital decision. In May 2022, the Energy & Utilities Board issued a partial decision approving a decrease in annual revenues of $1,041 to become effective in July 2022. In June 2022, the Court of Appeal found in favour of New Brunswick Gas and remanded the cost of capital case back to the Energy & Utilities Board. On December 22, 2022 the Board issued a Final Order and approved an annual revenue increase of $1,265 based on an ROE of 9.8%. New rates became effective January 1, 2023.
Apple Valley Ranchos Water System California GRC
Subsequent to year-end, on February 3, 2023, the Commission issued a Final Order authorizing an annual revenue increase of $1,412. New rates are retroactive to July 1, 2022.
Park Water System California GRC
Subsequent to year-end, on February 3, 2023, the Commission issued a Final Order authorizing an annual revenue increase of $1,105. New rates are retroactive to July 1, 2022.
7.Regulatory matters (continued)
Regulatory assets and liabilities consist of the following:
December 31, 2022 December 31, 2021
Regulatory assets
Fuel and commodity cost adjustments (a) $ 388,294 $ 339,900
Retired generating plant (b) 174,609 185,073
Rate adjustment mechanism (c) 136,198 117,309
Income taxes (d) 97,414 79,472
Deferred capitalized costs (e) 90,121 62,599
Pension and post-employment benefits (f) 80,736 134,287
Environmental remediation (g) 70,529 81,802
Wildfire mitigation and vegetation management (h) 66,156 35,726
Clean energy and other customer programs (i) 28,145 25,857
Asset retirement obligation (j) 27,172 26,810
Debt premium (k) 24,888 34,204
Cost of removal (l) 11,084 —
Rate review costs (m) 9,481 9,167
Long-term maintenance contract (n) 6,504 9,134
Other (o) 60,170 26,285
Total regulatory assets $ 1,271,501 $ 1,167,625
Less: current regulatory assets (190,393) (158,212)
Non-current regulatory assets $ 1,081,108 $ 1,009,413
Regulatory liabilities
Income taxes (d) $ 312,671 $ 295,720
Cost of removal (l) 191,173 191,981
Pension and post-employment benefits (f) 68,085 34,468
Fuel and commodity cost adjustments (a) 24,991 18,175
Clean energy and other customer programs (i) 11,572 14,829
Rate adjustment mechanism (c) 343 3,316
Other 19,347 17,700
Total regulatory liabilities $ 628,182 $ 576,189
Less: current regulatory liabilities (69,865) (65,809)
Non-current regulatory liabilities $ 558,317 $ 510,380

As recovery of regulatory assets is subject to regulatory approval, if there were any changes in regulatory positions that indicate recovery is not probable, the related cost would be charged to earnings in the period of such determination. The Company generally does not earn a return on the regulatory balances except for carrying charges on fuel and commodity cost adjustments (a), rate adjustment mechanism (c), clean energy and other customer programs (i), and rate review costs of some jurisdictions (m). Carrying charges on regulatory balances are recognized on the consolidated statement of operations under Interest and other income (note 8) and are computed using only the debt component of the allowed returned.
7.Regulatory matters (continued)
(a)Fuel and commodity cost adjustments
The revenue from the utilities includes a component that is designed to recover the cost of electricity and natural gas through rates charged to customers. To the extent actual costs of power or fuel purchased differ from power or fuel costs recoverable through current rates, that difference is deferred and recorded as a regulatory asset or liability on the consolidated balance sheets. These differences are reflected in adjustments to rates and recorded as an adjustment to cost of electricity and fuel in future periods ranging mostly from 6 to 24 months, subject to regulatory review. Derivatives are often utilized to manage the price risk associated with natural gas purchasing activities in accordance with the expectations of state regulators. The gains and losses associated with these derivatives (note 24(b)(i)) are recoverable through the commodity costs adjustment.
In February 2021, the Company's operations were impacted by extreme winter storm conditions experienced in Texas and parts of the central U.S. (“Midwest Extreme Weather Event”). As a result of the Midwest Extreme Weather Event, the Company incurred incremental commodity costs during the period of record high pricing and elevated consumption. The Company has commodity cost mechanisms that allow for the recovery of prudently incurred expenses.
In early 2022, pursuant to the securitization statute, Empire Electric sought authorization for the issuance of $221,646 in securitized utility tariff bonds associated with the Midwest Extreme Weather Event and $140,774, in securitized utility tariff bonds for its Asbury costs, which included $21,283 in asset retirement obligations, which are estimates of costs that Empire Electric will recover from the Asbury retirement but which have not yet been incurred. On April 27, 2022, the MPSC issued an order consolidating, for purposes of hearing, these two cases regarding the quantum financeable through securitization, which hearing was held the week of June 13, 2022. On August 18, 2022, and September 22, 2022, the MPSC issued and amended, respectively, a Report and Order authorizing Empire Electric to securitize $290,383 in qualified extraordinary costs (Midwest Extreme Weather Event), energy transition costs (Asbury) and upfront financing costs associated with the proposed securitization. The amounts authorized by the securitization order are generally consistent with the costs deferred by the Company in relation to these matters. Empire Electric filed a request for rehearing seeking reconsideration of the MPSC’s denial of recovery of five percent of the Midwest Extreme Weather Event costs, its calculation of accumulated deferred income taxes, and the exclusion of certain carrying charges associated with the Asbury plant, among other issues. On October 12, 2022, the MPSC denied all rehearing motions. Empire Electric appealed to the Missouri Court of Appeals - Western District on November 10, 2022. Briefing of the case is expected to be completed in April 2023.
(b)Retired generating plant
On March 1, 2020, the Company's 200 MW coal generation facility located in Asbury, Missouri, ceased operations. The Company transferred the remaining net book value of Asbury’s plant retired from plant in-service to a regulatory asset. The net book value that may be retained as an asset on the balance sheet for the retired plant is dependent upon amounts that may be recovered through regulated rates, including any return. An impairment charge, if any, would equal the difference between the remaining net book value of the asset and the present value of the future revenues expected from the asset. The ultimate valuation of the regulatory asset will be determined in future commission orders. The Company is also assessing the decommissioning requirements associated with the retirement of the facility.
Per commission orders in its jurisdictions, the Company is required to track the impact of Asbury's retirement on operating and capital expenses in Missouri for consideration in the next rate case. The Company recorded a regulatory liability for the estimated amount of revenues collected from customers for Asbury from March 1, 2020 to May 2022 that AQN determined was probable of refund. This regulatory liability did not include revenues collected related to the return on investment in Asbury as AQN determined that they were not probable of refund to customers based on the relevant facts and circumstances. AQN believes it is probable that the Asbury regulatory liability will be offset for recovery purposes against its unrecovered investment in Asbury and as a result, has netted its regulatory liability against its retired generation facilities regulatory asset.
As noted above under (a) Fuel and commodity cost adjustments, in March 2022, Empire Electric filed petitions for securitization of the impact of the Midwest Extreme Weather Event and the retirement of Asbury.
7.Regulatory matters (continued)
(c)Rate adjustment mechanism
Revenue for CalPeco Electric System, New England Gas System, Midstates Gas system, EnergyNorth Gas System, Granite State Electric System, Peach State Gas System and BELCO is subject to a revenue decoupling mechanism approved by their respective regulator, which allows revenue decoupling from sales. As a result, the difference between delivery revenue calculated based on metered consumption and approved delivery revenue is recorded as a regulatory asset or liability to reflect future recovery or refund, respectively, from customers over periods ranging from one to five years. The revenue from BELCO includes a component that is designed to recover budgeted capital and operating expenses for the current year. To the extent actual capital and operating expenditures are lower than the budgeted amounts, 80% of the shortfall is refundable to customers and is recorded as a regulatory liability. Retroactive rate adjustments for services rendered but to be collected over a period not exceeding 24 months are accrued upon approval of the final order. The difference between New Brunswick Gas' regulated revenues and its regulated cost of service in past years is also recorded as a regulatory asset and is recovered on a straight-line basis over 26 years. The Liberty NY Water System has similar trackers which are recovered over periods ranging from one to two years.
(d)Income taxes
The income taxes regulatory assets and liabilities represent income taxes recoverable through future revenues required to fund flow-through deferred income tax liabilities over the life of the plants and amounts owed to customers for deferred taxes collected at a higher rate than the current statutory rates.
(e)Deferred capitalized costs
Deferred capitalized costs reflect deferred construction costs and fuel-related costs of specific generating facilities of the Empire Electric System. These amounts are being recovered over the life of the plants. The amount also includes capitalized operating and maintenance costs of New Brunswick Gas, and these amounts are being recovered at a rate of 2.43% annually.
In 2020, the Empire Electric System made an election under Missouri law to apply the plant-in-service accounting (“PISA”) regulatory mechanism, which permits the Empire Electric System to defer, on a Missouri jurisdictional basis, 85% of the depreciation expense and carrying costs at the applicable WACC on certain property, plant, and equipment placed in service after the election date and not included in base rates. The portions of regulatory asset balances that are not yet being recovered through rates shall include carrying costs at the WACC, plus applicable federal, state, and local income or excise taxes. Regulatory asset balances included in rate base shall be recovered in rates through a 20-year amortization beginning on the effective date of new rates. The Company recognizes the cost of debt on PISA deferrals as reduction of interest expense. The difference between the WACC and cost of debt will be recognized in revenue when recovery of such deferrals is reflected in customer rates.
(f)Pension and post-employment benefits
To the extent pension and OPEB costs incurred differ from the costs recoverable through current rates, that difference is deferred and recorded as a regulatory asset or liability as approved by the applicable Regulators and is recovered through rates over a period of 3 to 8 years. In addition, the annual movements in AOCI for pension and OPEB for Empire Electric System, Empire Gas Systems, St. Lawrence Gas System and Liberty NY Water System (note 10(a)) are reclassified to regulatory accounts in accordance with ASC 980, Regulated Operations. The balance is recovered through rates consistent with the treatment of OCI under ASC 712, Compensation Non-retirement Post-employment Benefits and ASC 715, Compensation Retirement Benefits. As part of certain business acquisitions, the regulators authorized a regulatory asset or liability being set up for the amounts of pension and post-employment benefits that had not yet been recognized in net periodic cost and were presented as AOCI prior to the acquisition. These balances are recovered through rates over the future service years of the employees (an average of 10 years) or consistent with the treatment of OCI under ASC 712, Compensation Non-retirement Post-employment Benefits and ASC 715, Compensation Retirement Benefits before the transfer to regulatory asset occurred.
7.Regulatory matters (continued)
(g)Environmental remediation
Actual expenditures incurred for the clean-up of certain former natural gas manufacturing facilities (note 12(d)) are recovered through rates over a period of 7 years and are subject to an annual cap.
(h)Wildfire mitigation and vegetation management
The regulatory asset includes incremental wildfire liability insurance premium costs approved for tracking in the Company's California operations as well as the difference between actual and adopted spending related to dead trees program, to prevent future forest fires and general vegetation management. The assets are recovered over two years.
(i)Clean energy and other customer programs
The regulatory asset for clean energy and customer programs includes initiatives related to solar rebate applications processed and resulting rebate-related costs. The amount also includes other energy efficiency programs. The assets are generally included in rate base and recovered over periods of six to ten years.
(j)Asset retirement obligation
Asset retirement obligations are recorded for legally required removal costs of property, plant and equipment. The costs of retirement of assets as well as the on-going liability accretion and asset depreciation expense are expected to be recovered through rates once expenditures are made.
(k)Debt premium
Debt premium on acquired debt is recovered as a component of the weighted average cost of debt.
(l)Cost of removal
Rates charged to customers cover for costs that are expected to be incurred in the future to retire the utility plant. A regulatory liability (or asset) tracks the amounts that have been collected from customers net of costs incurred to date.
(m)Rate review costs
The cost to file, prosecute and defend rate review applications is referred to as rate review costs. These costs are capitalized and amortized over the period of rate recovery granted by the Regulator ranging from one to five years
(n)Long-term maintenance contract
To the extent actual costs of long-term maintenance incurred for one of Empire Electric System's power plants differ from the costs recoverable through current rates, that difference is generally included in rate base and recovered over five years.
(o) Other
The Company’s regulated utilities incur other miscellaneous costs such as storm costs, property taxes, financing costs, and equipment costs, which are probable of recovery under existing mechanisms.

v3.23.1

Long-term investments
12 Months Ended

Dec. 31, 2022

Disclosure Long Term Investments And Notes Receivable [Abstract]

Long-term investments Long-term investments
Long-term investments consist of the following:
December 31, 2022 December 31, 2021
Long-term investments carried at fair value
Atlantica (a) $ 1,268,140 $ 1,750,914
Atlantica Yield Energy Solutions Canada Inc. (b) 74,083 95,246
Other 1,984 2,296
$ 1,344,207 $ 1,848,456
Other long-term investments
Equity-method investees (c) $ 381,802 $ 433,850
Development loans receivable from equity-method investees (d) 52,923 31,468
San Antonio Water System and other (e) 27,600 30,508
$ 462,325 $ 495,826
Fair value change, income (loss) and impairment expense related to long-term investments from the years ended December 31 is as follows:
Year ended December 31,
2022 2021
Fair value gain (loss) on investments carried at fair value
Atlantica $ (482,774) $ (107,030)
Atlantica Yield Energy Solutions Canada Inc. (16,018) (15,915)
Other (333) 526
$ (499,125) $ (122,419)
Dividend and interest income from investments carried at fair value
Atlantica $ 86,664 $ 83,971
Atlantica Yield Energy Solutions Canada Inc. 20,443 17,222
Other 36 330
$ 107,143 $ 101,523
Other long-term investments
Equity method loss (c) $ (21,416) $ (26,337)
Impairment of equity-method investee (c) (75,910) —
Interest and other income 24,102 20,776
$ (73,224) $ (5,561)
Fair value change, income (loss) and impairment expense related to long-term investments $ (465,206) $ (26,457)

(a)Investment in Atlantica
Liberty (AY Holdings) B.V. (“AY Holdings”), an entity controlled and consolidated by AQN, has a share ownership in Atlantica Sustainable Infrastructure PLC (“Atlantica”) of approximately 42% (2021 - 44%). AQN has the flexibility, subject to certain conditions, to increase its ownership of Atlantica up to 48.5%. The total cost for the Atlantica shares as of December 31, 2022 is $1,167,444 (2021 - $1,167,444).
The Company has elected the fair value option under ASC 825, Financial Instruments to account for its investment in Atlantica, with changes in fair value reflected in the consolidated statements of operations.
8.Long-term investments (continued)
(b)Investment in AYES Canada
AQN and Atlantica own Atlantica Yield Energy Solutions Canada Inc. (“AYES Canada”), a vehicle to channel co-investment opportunities in which Atlantica holds the majority of voting rights. AYES Canada invested in Windlectric Inc. (“Windlectric”). The investment by AYES Canada in Windlectric is presented as a non-controlling interest held by a related party (notes 17).
AYES Canada is considered to be a VIE based on the disproportionate voting and economic interests of the shareholders. Atlantica is considered to be the primary beneficiary of AYES Canada. Accordingly, AQN's investment in AYES Canada is considered an equity method investment. Under the AYES Canada shareholders agreement, AQN has the option to exchange approximately 3,500,000 shares of AYES Canada into ordinary shares of Atlantica on a one-for-one basis, subject to certain conditions. Consistent with the treatment of the Atlantica shares, the Company has elected the fair value option under ASC 825, Financial Instruments to account for its investment in AYES Canada, with changes in fair value reflected in the consolidated statements of operations.
As at December 31, 2022, the Company's maximum exposure to loss is $74,083 (2021 - $95,246), which represents the fair value of the investment.
(c)Equity-method investees
The Renewable Energy Group has non-controlling interests in operating renewable energy facilities and projects under construction with a total carrying value of $310,103 (2021 - $375,460). The Regulated Services Group has non-controlling interest of $56,199 (2021 - 37,492) in a power transmission line project under construction and other non-regulated operating entities owned by its utilities. The Liberty Development JV Inc. platform for non-regulated renewable energy, water and other sectors has a carrying value of $15,500 and (2021 - $20,898) is reported under Corporate.
Operating entities: The Company has interests in the operating entities listed below. The Company is not considered the primary beneficiary as the two partners have joint control and all key decisions must be unanimous. As such, the Company accounts for its interests using the equity method.
Economic interest Capacity
Texas Coastal Wind Facilities 51 % 861 MW
Blue Hill Wind Facility 20 % 175 MW
Red Lily Wind Facility 75 % 26.4 MW
Val-Eo Wind Facility 50 % 24 MW
During 2021, the Company acquired a 51% interest in four wind facilities located in Texas (“Texas Coastal Wind Facilities”) for $344,883. All facilities achieved commercial operations in 2021. As at December 31, 2022, the Company had issued $113,630 (2021 - $119,750) in letters of credit and guarantees of performance obligations under energy purchase agreements and decommissioning obligations on behalf of the Texas Coastal Wind Facilities. During the fourth quarter of 2022, the Company concluded that primarily as a result of continued challenges with congestion at the facilities, the carrying value of the interest in the Texas Coastal Wind Facilities was other-than-temporarily impaired. Accordingly, the Company performed a fair value analysis based on the income approach and recorded an impairment charge of $75,910 to reduce the carrying value of its equity investment in the Texas Coastal Wind Facilities from $282,726 to 206,816. Changes in assumptions of revenue forecasts, driven by expected production, basis difference and resulting spot prices, projected operating and capital expenditures would affect the estimated fair value.
Development: Pursuant to an agreement between AQN and funds managed by the Infrastructure and Power strategy of Ares Management, LLC (“Ares”), in November 2021 Ares became AQN’s new partner in its non-regulated development platform for renewable energy, water and other sectors as both parties contributed cash or assets of $19,688 to Liberty Development JV Inc. The Company is not considered the primary beneficiary as the two partners have joint control and all key decisions must be unanimous. As such, the Company accounts for its interests using the equity method.
8.Long-term investments (continued)
(c)Equity-method investees (continued)
Construction: The Renewable Energy Group has 50% equity interests in several wind and solar power electric construction projects. AQN and Ares have formed Liberty Construction (US) JV LLC (“Liberty Construction JV”) to jointly construct projects under the Renewable Energy Group. During the year, the Company contributed several projects to joint entities. The transfers resulted in a gain of $nil (2021 - $26,182). The Company holds an option to acquire the remaining interest in most construction projects at a pre-agreed price. The Company is not considered the primary beneficiary as the partners have joint control and all key decisions must be unanimous. As such, the Company accounts for its interests using the equity method.
Changes in the carrying value of equity method investees were as follows:
2022 2021
Carrying value, January 1 $ 433,850 $ 186,452
Additional Investments 110,441 418,434
Net loss attributable to AQN (21,416) (26,337)
Other comprehensive income (loss) attributable to AQN (a) (67,110) 7,733
Operating projects bought back by AQN — (129,075)
Dividend received (1,183) (2,981)
Impairment (75,910) —
Reclassification during the period (note 8(e)) — (25,634)
Other 3,130 5,258
Carrying value, December 31 $ 381,802 $ 433,850
(a) Other comprehensive loss represents the Company’s proportion of the change in fair value, recorded in OCI at the investee level, on energy derivative financial instruments designated as a cash flow hedge,

Summarized combined information for AQN's equity method investees as at December 31 is as follows:
2022 2021
Total assets $ 2,740,132 $ 2,126,934
Total liabilities 1,507,079 945,971
Net assets 1,233,053 1,180,963
AQN's ownership interest in the entities 332,663 327,555
Difference between investment carrying amount and underlying equity in net assets(a)
49,139 106,295
Total carrying value $ 381,802 $ 433,850
(a) The difference between the investment carrying amount and the underlying equity in net assets relates primarily to interest capitalized while the projects are under construction, the fair value of guarantees provided by the Company in regards to the investments, development fees and transaction costs.
8.Long-term investments (continued)
(c)Equity-method investees (continued)
Summarized combined information for AQN's equity method investees for the year ended December 31 (presented at 100%) is as follows:
2022 2021
Revenue $ 65,025 $ 20,262
Net loss $ (31,070) $ (46,293)
Other comprehensive income (loss) (a)
$ (130,729) $ 15,177
Net loss attributable to AQN $ (21,416) $ (26,337)
Other comprehensive loss attributable to AQN (a)
$ (67,110) $ 7,733

(a) Other comprehensive loss represents the Company’s proportion of the change in fair value, recorded in OCI at the investee level, on energy derivative financial instruments designated as a cash flow hedge,

Except for Liberty Global Energy Solutions B.V. (formerly Abengoa-Algonquin Global Energy Solutions B.V.) (“Liberty Global Energy Solutions”), Liberty Development JV Inc. and all construction projects are considered VIEs due to the level of equity at risk and the disproportionate voting and economic interests of the shareholders. The Company has committed loan and credit support facilities with some of its equity investees. During construction, the Company has agreed to provide cash advances and credit support for the continued development and construction of the equity investees' projects. As of December 31, 2022, the Company had issued letters of credit and guarantees of performance obligations: under a security of performance for a development opportunity; wind turbine or solar panel supply agreements; engineering, procurement, and construction agreements; interconnection agreements; energy purchase agreements; renewable energy credit agreements; and construction loan agreements. The fair value of the support provided recorded as at December 31, 2022 amounts to $8,824 (2021 - $4,612).
Summarized combined information for AQN's VIEs as at December 31 is as follows:
2022 2021
AQN's maximum exposure in regards to VIEs
Carrying amount $ 122,752 $ 86,202
Development loans receivable (d) 52,923 31,468
Performance guarantees and other commitments on behalf of VIEs 658,224 409,232
$ 833,899 $ 526,902
The commitments are presented on a gross basis assuming no recoverable value in the assets of the VIEs. The majority of the amounts committed on behalf of VIEs in the above relate to wind turbine or solar panel supply agreements as well as engineering, procurement, and construction agreements.
(d)Development loans receivable from equity investees
The Renewable Energy Group has committed loan and credit support facilities with some of its equity investees. During construction, the Company has agreed to provide cash advances and credit support (in the form of letters of credit, escrowed cash, guarantees or indemnities) in amounts necessary for the continued development and construction of the equity investees' projects. The loans generally mature on the twelfth anniversary of the development agreement or commercial operation date.
(e)San Antonio Water System and other
The Company no longer has significant influence over its 20% interest in the San Antonio Water System (“SAWS”), and therefore has discontinued the equity method of accounting in 2021. The investment is accounted for using the cost method prospectively.

v3.23.1

Long-term debt
12 Months Ended

Dec. 31, 2022

Debt Disclosure [Abstract]

Long-term debt Long-term debt
Long-term debt consists of the following:
Borrowing type Weighted average coupon Maturity Par value December 31, 2022 December 31, 2021
Senior unsecured revolving credit facilities (a) — 2024-2027 N/A $ 351,786 $ 368,806
Senior unsecured bank credit facilities and delayed draw term facility (b) — 2023-2031 N/A 773,643 141,956
Commercial paper — 2023 N/A 407,000 338,700
U.S. dollar borrowings
Senior unsecured notes (Green Equity Units) (c) 1.18 % 2026 $ 1,150,000 1,142,814 1,140,801
Senior unsecured notes (d) 3.39 % 2023-2047 $ 1,505,000 1,496,101 1,689,792
Senior unsecured utility notes 6.34 % 2023-2035 $ 142,000 154,271 155,571
Senior secured utility bonds 4.71 % 2026-2044 $ 556,209 554,822 558,177
Canadian dollar borrowings
Senior unsecured notes (e) 3.68 % 2027-2050 C$ 1,200,000 882,899 1,099,403
Senior secured project notes 10.21 % 2027 C$ 20,349 15,024 18,344
Chilean Unidad de Fomento borrowings
Senior unsecured utility bonds 4.05 % 2028-2040 CLF 1,637 77,206 77,963
$ 5,855,566 $ 5,589,513
Subordinated U.S. dollar borrowings
Subordinated unsecured notes (f) 5.25 % 2082 C$ 400,000 291,238 —
Subordinated unsecured notes (f) 5.56 % 2078-2082 $ 1,387,500 1,365,213 621,862
$ 7,512,017 $ 6,211,375
Less: current portion (423,274) (356,397)
$ 7,088,743 $ 5,854,978
Short-term obligations of $705,386 that are expected to be refinanced using the long-term credit facilities are presented as long-term debt.
Long-term debt issued at a subsidiary level (project notes or utility bonds) relating to a specific operating facility is generally collateralized by the respective facility with no other recourse to the Company. Long-term debt issued at a subsidiary level whether or not collateralized generally has certain financial covenants, which must be maintained on a quarterly basis. Non-compliance with the covenants could restrict cash distributions/dividends to the Company from the specific facilities.
9.Long-term debt (continued)
The following table sets out the bank credit facilities available to AQN and its operating groups as at December 31, 2022:
December 31, 2022 December 31, 2021
Revolving and term credit facilities $ 4,513,300 $ 3,217,000
Funds drawn on facilities/ commercial paper issued (1,532,500) (849,600)
Letters of credit issued (465,200) (317,200)
Liquidity available under the facilities 2,515,600 2,050,200
Undrawn portion of uncommitted letter of credit facilities (226,900) (224,000)
Cash on hand 57,623 125,157
Total liquidity and capital reserves $ 2,346,323 $ 1,951,357
Recent financing activities:
(a)Senior unsecured revolving credit facilities
Regulated Services Group
On April 29, 2022, the Regulated Services Group entered into two new senior unsecured revolving credit facilities: a $1,000,000 senior unsecured revolving credit facility with an initial maturity date of April 29, 2027 (the “Long-Term Regulated Services Credit Facility”) and a $500,000 short-term senior unsecured revolving credit facility maturing originally on March 31, 2023 and extended to February 28, 2024, subsequent to year-end. Subject to the terms and conditions therein, the Long-Term Regulated Services Credit Facility may be extended for two additional one-year periods. In conjunction with the new facilities, the Regulated Services Group’s $500,000 senior unsecured syndicated revolving credit facility was cancelled.
On December 23, 2022, the Regulated Services Group amended and restated its $75,000 senior unsecured revolving credit facility in Bermuda with a new maturity date of December 31, 2024. On June 24, 2022, the Regulated Services Group entered into a new $25,000 senior unsecured bilateral revolving credit facility in Bermuda that matures on June 24, 2024.
Renewable Energy Group
On July 22, 2022, the Renewable Energy Group amended and restated its $500,000 senior unsecured syndicated revolving credit facility (the "Renewable Energy Credit Facility") with a new maturity date of July 22, 2027. Subject to the terms and conditions therein, the Renewable Energy Credit Facility may be extended for additional one-year periods.
On July 22, 2022, the Renewable Energy Group entered into a new $250,000 uncommitted bilateral letter of credit facility. On November 8, 2022, the Renewable Energy Group's $350,000 uncommitted letter of credit facility was amended and restated with a new maturity date of June 30, 2024.
(b)Senior unsecured bank credit facilities
On November 30, 2022, the Regulated Services Group amended and restated its $1,100,000 senior unsecured delayed draw term facility ("the "Regulated Services Delayed Draw Term Facility") with the new maturity date of November 29, 2023.
(c)U.S dollar senior unsecured notes (Green Equity Units)
In June 2021, the Company sold 23,000,000 equity units (the “Green Equity Units”) for total gross proceeds of $1,150,000. Each Green Equity Unit was issued in a stated amount of $50, at issuance, consisted of a contract to purchase AQN common shares (the “share purchase contract”) and a 5% undivided beneficial ownership interest in a remarketable senior note of AQN due June 15, 2026, issued in the principal amount of $1,000.
9.Long-term debt (continued)
Recent financing activities (continued):
(c)U.S dollar senior unsecured notes (Green Equity Units) (continued)
Total annual distributions on the Green Equity Units are at a rate of 7.75%, consisting of interest on the notes (1.18% per year) and payments under the share purchase contract (6.57% per year). The interest rate on the notes will be reset following a successful marketing, which would occur in 2024. The present value of the contract adjustment payments was estimated at $222,378 and is recorded against additional paid-in capital (“APIC”) to the extent of the APIC balance and against retained earnings (deficit) for the remainder. The corresponding amount of $222,378 was recorded in other liabilities and is accreted over the three-year period (note 12(a)).
Each share purchase contract requires the holder to purchase by no later than June 15, 2024 for a price of $50 in cash, a number of AQN common shares (“common shares”) based on the applicable market value to be determined using the volume-weighted average price of the common shares over a 20-day trading period ending June 14, 2024. The minimum settlement rate under the purchase contracts is 2.7778 common shares, which is approximately equal to the $50 stated amount per Green Equity Unit, divided by the threshold appreciation price of $18 per common share. The maximum settlement rate under the purchase contracts is 3.3333 common shares, which is approximately equal to the $50 stated amount per Green Equity Unit, divided by $15 per common share.
The common share purchase obligation of holders of Green Equity Units will be satisfied by the proceeds raised from a successful remarketing of the notes, unless a holder has elected to settle with separate cash. Holders’ beneficial ownership interest in each note has been pledged to AQN to secure the holders' obligation to purchase common shares under the related share purchase contract.
Prior to the issuance of common shares, the share purchase contracts, if dilutive, will be reflected in the Company's diluted earnings per share calculations using the treasury stock method.
(d)U.S. dollar senior unsecured notes
On April 30, 2022, the Company repaid a $80,000 senior unsecured note on its maturity.
On August 1, 2022, the Company repaid a $115,000 senior unsecured note on its maturity.
Subsequent to year end, the Company repaid a $15,000 senior unsecured note on its maturity.
(e)Canadian dollar senior unsecured notes
On February 15, 2022, the Company repaid a C$200,000 senior unsecured note on its maturity. On February 15, 2021, the Renewable Energy Group repaid a C$150,000 unsecured note upon its maturity. Concurrent with the repayments, the Renewable Energy Group unwound and settled the related cross-currency fixed-for-fixed interest rate swap (note 24(b)(iii)).
On April 9, 2021, the Renewable Energy Group issued C$400,000 senior unsecured debentures bearing interest at 2.85% with a maturity date of July 15, 2031. The notes were sold at a price of C$999.92 per C$1,000.00 principal amount. Concurrent with the offering, the Renewable Energy Group entered into a fixed-for-fixed cross-currency interest rate swap to convert the Canadian-dollar-denominated coupon and principal payments from the offering into U.S. dollars (note 24(b)(iii)).
9.Long-term debt (continued)
Recent financing activities (continued):
(f)Subordinated unsecured notes
On January 18, 2022, the Company closed (i) an underwritten public offering in the United States (the “U.S. Offering”) of $750,000 aggregate principal amount of 4.75% fixed-to-fixed reset rate junior subordinated notes series 2022-B due January 18, 2082 (the “U.S. Notes”); and (ii) an underwritten public offering in Canada (the “Canadian Offering” and, together with the U.S. Offering, the “Offerings”) of C$400,000 (approximately $320,000) aggregate principal amount of 5.25% fixed-to-fixed reset rate junior subordinated notes series 2022-A due January 18, 2082 (the “Canadian Notes” and, together with the U.S. Notes, the “Notes”). Concurrent with the pricing of the Offerings, the Company entered into a cross currency interest rate swap to convert the Canadian dollar denominated proceeds from the Canadian Offering into U.S. dollars, and a forward starting swap to fix the interest rate for the second five year term of the U.S. Notes, resulting in an anticipated effective interest rate to the Company of approximately 4.95% throughout the first ten-year period of the Notes.

As of December 31, 2022, the Company had accrued $70,274 in interest expense (2021 - $49,806). Interest expense for the years ended December 31 consists of the following:
2022 2021
Long-term debt $ 261,535 $ 217,123
Commercial paper, credit facility draws and related fees 43,015 17,065
Accretion of fair value adjustments (16,547) (18,174)
Capitalized interest and AFUDC capitalized on regulated property (10,802) (6,521)
Other 1,373 61
$ 278,574 $ 209,554

Principal payments due in the next five years and thereafter are as follows:
2023 2024 2025 2026 2027 Thereafter Total
$ 1,128,660 $ 359,371 $ 45,262 $ 1,265,711 $ 719,144 $ 4,019,166 $ 7,537,314

v3.23.1

Pension and other post-retirement benefits
12 Months Ended

Dec. 31, 2022

Retirement Benefits [Abstract]

Pension and other post-retirement benefits Pension and other post-employment benefits
The Company provides defined contribution pension plans to substantially all of its employees. The Company’s contributions for 2022 were $12,126 (2021 - $10,836).
The Company provides a defined benefit cash balance pension plan under which employees are credited with a percentage of base pay plus a prescribed interest rate credit. In conjunction with the utility acquisitions, the Company also assumes defined benefit pension, SERP and OPEB plans for qualifying employees in the related acquired businesses. The legacy plans are non-contributory defined pension plans covering substantially all employees of the acquired businesses. Benefits are based on each employee’s years of service and compensation. The Company permanently freezes the accrual of benefits for participants in legacy plans. Thereafter, employees accrue benefits under the Company’s cash balance plan. The OPEB plans provide health care and life insurance coverage to eligible retired employees. Eligibility is based on age and length of service requirements and, in most cases, retirees must cover a portion of the cost of their coverage.
10.Pension and other post-employment benefits (continued)
(a)Net pension and OPEB obligation
The following table sets forth the projected benefit obligations, fair value of plan assets, and funded status of the Company’s plans as of December 31:
Pension benefits OPEB
2022 2021 2022 2021
Change in projected benefit obligation
Projected benefit obligation, beginning of year $ 765,618 $ 834,913 $ 292,646 $ 306,524
Projected benefit obligation assumed from business combination 87,933 — 5,195 —
Plan Settlements (112) (1,294) — —
Service cost 16,309 14,673 6,277 7,307
Interest cost 24,787 20,676 9,146 8,048
Actuarial gain (198,074) (36,597) (82,991) (18,977)
Contributions from retirees — — 2,220 2,040
Plan amendments — 237 (2,452) 310
Medicare Part D — — 367 373
Benefits paid (68,197) (66,800) (13,078) (12,979)
Foreign exchange (129) (190) — —
Projected benefit obligation, end of year $ 628,135 $ 765,618 $ 217,330 $ 292,646
Change in plan assets
Fair value of plan assets, beginning of year 648,864 629,157 192,375 176,616
Plan assets acquired in business combination 74,532 — 8,577 —
Actual return on plan assets (109,118) 58,721 (30,105) 15,200
Employer contributions 23,296 29,058 11,811 11,178
Plan Settlements (112) (1,294) — —
Contributions from retirees — — 2,220 1,988
Medicare Part D subsidy receipts — — 367 372
Benefits paid (68,197) (66,800) (13,078) (12,979)
Foreign exchange (10) 22 — —
Fair value of plan assets, end of year $ 569,255 $ 648,864 $ 172,167 $ 192,375
Unfunded status $ (58,880) $ (116,754) $ (45,163) $ (100,271)
Amounts recognized in the consolidated balance sheets consist of:
Non-current assets (note 11) 12,264 11,751 14,218 11,879
Current liabilities (1,907) (1,902) (3,039) (699)
Non-current liabilities (69,237) (126,603) (56,342) (111,451)
Net amount recognized
$ (58,880) $ (116,754) $ (45,163) $ (100,271)
The accumulated benefit obligation for the pension and OPEB plans was $815,589 and $1,080,685 as of December 31, 2022 and 2021, respectively.
10.Pension and other post-employment benefits (continued)
(a)Net pension and OPEB obligation (continued)
Information for pension and OPEB plans with an accumulated benefit obligation in excess of plan assets:
Pension OPEB
2022 2021 2022 2021
Accumulated benefit obligation $ 413,041 $ 489,043 $ 198,463 $ 274,649
Fair value of plan assets $ 364,229 $ 396,679 $ 139,368 $ 162,592

Information for pension and OPEB plans with a projected benefit obligation in excess of plan assets:
Pension OPEB
2022 2021 2022 2021
Projected benefit obligation $ 489,140 $ 580,841 $ 198,463 $ 274,649
Fair value of plan assets $ 417,994 $ 452,333 $ 139,368 $ 162,592

(b)Pension and post-employment actuarial changes
Change in AOCI, before tax Pension OPEB
Actuarial losses (gains) Past service gains Actuarial losses (gains) Past service losses (gains)
Balance, January 1, 2021 $ 57,231 $ (5,306) $ (4,299) $ —
Additions to AOCI (59,754) 237 (24,126) (24)
Amortization in current period (13,130) 1,626 (2,021) 334
Amortization due to plan settlements (210) — — —
Reclassification to regulatory accounts 31,670 (752) 14,816 —
Balance, December 31, 2021 $ 15,807 $ (4,195) $ (15,630) $ 310
Additions to AOCI (47,473) — (41,527) (24)
Amortization in current period (3,429) 1,584 56 (2,476)
Amortization due to plan settlements 15 — — —
Reclassification to regulatory accounts 34,409 (752) 23,551 —
Balance, December 31, 2022 $ (671) $ (3,363) $ (33,550) $ (2,190)
The movements related to pension and OPEB in AOCI for Empire Electric System, Empire Gas Systems, St. Lawrence Gas System and Liberty NY Water System are reclassified to regulatory accounts since it is probable the unfunded amount of these plans will be afforded rate recovery (note 7(f)).
10.Pension and other post-employment benefits (continued)
(c)Assumptions
Weighted average assumptions used to determine net benefit obligation for 2022 and 2021 were as follows:
Pension benefits OPEB
2022 2021 2022 2021
Discount rate 5.48 % 2.94 % 5.49 % 3.00 %
Interest crediting rate (for cash balance plans) 4.50 % 4.00 % N/A N/A
Rate of compensation increase 3.70 % 4.00 % N/A N/A
Health care cost trend rate
Before age 65 6.00 % 5.88 %
Age 65 and after 6.00 % 5.88 %
Assumed ultimate medical inflation rate 4.75 % 4.75 %
Year in which ultimate rate is reached 2033 2031
The mortality assumption for December 31, 2022 uses the Pri-2012 mortality table and the projected generationally scale MP-2021, adjusted to reflect the ultimate improvement rates in the 2021 Social Security Administration intermediate assumptions for plans in the United States. The mortality assumption for the Bermuda plan as of December 31, 2022 uses the 2014 Canadian Pensioners' Mortality Table combined with mortality improvement scale CPM-B.
In selecting an assumed discount rate, the Company uses a modelling process that involves selecting a portfolio of high-quality corporate debt issuances (AA- or better) whose cash flows (via coupons or maturities) match the timing and amount of the Company’s expected future benefit payments. The Company considers the results of this modelling process, as well as overall rates of return on high-quality corporate bonds and changes in such rates over time, to determine its assumed discount rate.
The rate of return assumptions are based on projected long-term market returns for the various asset classes in which the plans are invested, weighted by the target asset allocations.
Weighted average assumptions used to determine net benefit cost for 2022 and 2021 were as follows:
Pension benefits OPEB
2022 2021 2022 2021
Discount rate 2.94 % 2.49 % 3.00 % 2.58 %
Expected return on assets 6.19 % 6.20 % 6.48 % 4.79 %
Rate of compensation increase 3.91 % 3.99 % n/a n/a
Health care cost trend rate
Before Age 65 5.88 % 5.12 %
Age 65 and after 5.88 % 5.12 %
Assumed ultimate medical inflation rate 4.75 % 4.05 %
Year in which ultimate rate is reached 2031 2031
10.Pension and other post-employment benefits (continued)
(d)Benefit costs
The following table lists the components of net benefit cost for the pension and OPEB plans. Service cost is recorded as part of operating expenses and non-service costs are recorded as part of other net losses in the consolidated statements of operations. The employee benefit costs related to businesses acquired are recorded in the consolidated statements of operations from the date of acquisition.
Pension benefits OPEB
2022 2021 2022 2021
Service cost $ 16,309 $ 14,673 $ 6,277 $ 7,307
Non-service costs
Interest cost 24,787 20,676 9,146 8,048
Expected return on plan assets (41,226) (35,972) (11,359) (10,052)
Amortization of net actuarial loss 3,452 13,126 (56) 2,021
Amortization of prior service credits (1,584) (1,626) 24 11
Amortization due to plan settlements (15) 198 — —
Amortization of regulatory accounts 22,951 19,665 4,829 218
$ 8,365 $ 16,067 $ 2,584 $ 246
Net benefit cost $ 24,674 $ 30,740 $ 8,861 $ 7,553
(e)Plan assets
The Company’s investment strategy for its pension and post-employment plan assets is to maintain a diversified portfolio of assets with the primary goal of meeting long-term cash requirements as they become due.
The Company’s target asset allocation is as follows:
Asset class Target (%) Range (%)
Equity securities 41 %
30% -100%
Debt securities 49 %
20% - 60%
Other 10 %
0% - 20%
100 %

The fair values of investments as of December 31, 2022, by asset category, are as follows:
Asset class 2022 Percentage
Equity securities $ 317,088 43 %
Debt securities 356,654 48 %
Other 67,680 9 %
$ 741,422 100 %
As of December 31, 2022, the plan assets do not include any material investments in AQN.
10.Pension and other post-employment benefits (continued)
(e)Plan assets (continued)
All investments as of December 31, 2022 were valued using level 1 inputs except for 21,904 of institutional private equity investments using level 3 fair value measurement. These private equity funds invest in the private equity secondary market and in the credit markets. These funds are not traded in the open market, and are valued based on the underlying securities within the funds. The underlying securities are valued at fair value by the fund managers by using securities exchange quotations, pricing services, obtaining broker-dealer quotations, reflecting valuations provided in the most recent financial reports, or at a good faith estimate using fair market value principles.
The following table summarizes the changes fair value of these level 3 assets as of December 31:
Level 3
Balance, January 1, 2022 $ 17,314
Contributions into funds 4,781
Return on assets 2,094
Distributions (2,285)
Balance, December 31, 2022 $ 21,904
(f)Cash flows
The Company expects to contribute $22,386 to its pension plans and $9,819 to its post-employment benefit plans in 2023.
The expected benefit payments over the next ten years are as follows:
2023 2024 2025 2026 2027 2028-2032
Pension plan $ 48,174 $ 47,428 $ 49,794 $ 50,585 $ 50,433 $ 259,082
OPEB $ 11,483 $ 12,025 $ 12,548 $ 12,925 $ 13,479 $ 72,684

v3.23.1

Other assets
12 Months Ended

Dec. 31, 2022

Deferred Costs, Capitalized, Prepaid, and Other Assets Disclosure [Abstract]

Other assets Other assets
Other assets consist of the following:
2022 2021
Restricted cash $ 43,562 $ 36,232
Pension and OPEB plan assets (note 10(a)) 26,482 23,630
Long-term deposits and cash collateral 22,537 14,713
Income taxes recoverable 7,100 7,649
Deferred financing costs (a) 28,586 30,544
Other (b) 21,596 10,913
$ 149,863 $ 123,681
Less: current portion (22,564) (16,153)
$ 127,299 $ 107,528
(a)Deferred financing costs
Deferred financing costs represent costs of arranging the Company’s revolving credit facilities and intercompany loans as well as the portion of transactions costs related to the Green Equity Units (note 9(c)) that will be recorded against the common shares when issued.

(b)Other
Other includes various deferred charges that are expected to be transferred to utility plant upon reaching certain milestones as well as prepaid long-term service contracts.

v3.23.1

Other long-term liabilities
12 Months Ended

Dec. 31, 2022

Other Liabilities Disclosure [Abstract]

Other long-term liabilities Other long-term liabilities
Other long-term liabilities consist of the following:
2022 2021
Contract adjustment payments (a) $ 113,876 $ 187,580
Asset retirement obligations (b) 116,584 142,147
Advances in aid of construction (c) 88,546 82,584
Environmental remediation obligation (d) 42,457 55,224
Customer deposits (e) 34,675 32,629
Unamortized investment tax credits (f) 17,649 17,439
Deferred credits and contingent consideration (g) 39,498 43,495
Preferred shares, Series C (h) 12,072 13,348
Hook up fees (i) 32,463 21,904
Lease liabilities (note 1(q)) 21,834 22,512
Contingent development support obligations (j) 8,824 4,615
Note payable to related party (k) 25,808 25,808
Other 41,156 34,534
$ 595,442 $ 683,819
Less: current portion (134,212) (167,908)
$ 461,230 $ 515,911
(a)Contract adjustment payment
In June 2021, the Company sold 23,000,000 Green Equity Units for total gross proceeds of $1,150,000 (note 9(c)). Total annual distributions on the Green Equity Units are at a rate of 7.75%, consisting of interest on the notes (1.18% per year) and payments under the share purchase contract (6.57% per year). The present value of the contract adjustment payments was estimated at $222,378 and recorded in other liabilities. The contract adjustment payments amount is accreted over the three-year period.
(b)Asset retirement obligations
    Asset retirement obligations mainly relate to legal requirements to: (i) remove wind farm facilities upon termination of land leases; (ii) cut (disconnect from the distribution system), purge (cleanup of natural gas and polychlorinated biphenyls (“PCB”) contaminants) and cap natural gas mains within the natural gas distribution and transmission system when mains are retired in place, or sections of natural gas main are removed from the pipeline system; (iii) clean and remove storage tanks containing waste oil and other waste contaminants; (iv) remove certain river water intake structures and equipment; (v) dispose of coal combustion residuals and PCB contaminants; (vi) remove asbestos upon major renovation or demolition of structures and facilities; and (vii) decommission and restore power generation engines and related facilities.
Changes in the asset retirement obligations are as follows:
2022 2021
Opening balance $ 142,147 $ 79,968
Obligation assumed 793 57,067
  Retirement activities (27,980) (4,133)
  Accretion 4,589 4,381
  Change in cash flow estimates (2,965) 4,864
Closing balance $ 116,584 $ 142,147
12.Other long-term liabilities (continued)
(b)Asset retirement obligations (continued)
As the cost of retirement of utility assets in the United States is expected to be recovered through rates, a corresponding regulatory asset is recorded for liability accretion and asset depreciation expense (note 7(j)).
(c)Advances in aid of construction
The Company’s regulated utilities have various agreements with real estate development companies (the “developers”) conducting business within the Company’s utility service territories, whereby funds are advanced to the Company by the developers to assist with funding some or all of the costs of the development.
In many instances, developer advances can be subject to refund, but the refund is non-interest bearing. Refunds of developer advances are made over periods generally ranging from 5 to 40 years. Advances not refunded within the prescribed period are usually not required to be repaid. After the prescribed period has lapsed, any remaining unpaid balance is transferred to contributions in aid of construction and recorded as an offsetting amount to the cost of property, plant and equipment. In 2022, $1,299 (2021 - $6,376) was transferred from advances in aid of construction to contributions in aid of construction.
(d)Environmental remediation obligation
A number of the Company's regulated utilities were named as potentially responsible parties for remediation of several sites at which hazardous waste is alleged to have been disposed as a result of historical operations of manufactured natural gas plants (“MGP”) and related facilities. The Company is currently investigating and remediating, as necessary, those MGP and related sites in accordance with plans submitted to the agency with authority for each of the respective sites.
The Company estimates the remaining undiscounted, unescalated cost of the environmental cleanup activities will be $48,346 (2021 - $57,167), which at discount rates ranging from 3.4% to 4.2% represents the recorded accrual of $42,457 as of December 31, 2022 (2021 - $55,224 ). Approximately $27,410 is expected to be incurred over the next three years, with the balance of cash flows to be incurred over the following 30 years.
Changes in the environmental remediation obligation are as follows:
2022 2021
Opening balance $ 55,224 $ 69,383
  Remediation activities (5,243) (9,865)
  Accretion 2,167 1,025
  Changes in cash flow estimates 1,344 2,265
  Revision in assumptions (11,035) (7,584)
Closing balance $ 42,457 $ 55,224
The Regulators for the New England Gas System and Energy North Gas System provide for the recovery of actual expenditures for site investigation and remediation over a period of 7 years and, accordingly, as of December 31, 2022, the Company has reflected a regulatory asset of $70,529 (2021 - $81,802) for the MGP and related sites (note 7(g)).
(e)Customer deposits
Customer deposits result from the Company’s obligation by Regulators to collect a deposit from customers of its facilities under certain circumstances when services are connected. The deposits are refundable as allowed under the facilities’ regulatory agreement.
12.Other long-term liabilities (continued)
(f)Unamortized investment tax credits
The unamortized investment tax credits were assumed in connection with the acquisition of the Empire Electric System. The investment tax credits are associated with an investment made in a generating station. The credits are being amortized over the life of the generating station.
(g)Deferred credits and contingent consideration
Deferred credits and contingent consideration include unresolved contingent consideration related to prior acquisitions which is expected to be paid. In 2021, the Company recorded contingent consideration related to the acquisition of AAGES Sugar Creek Wind, LLC in an amount of $18,641 (note 3(f)).
(h)Preferred shares, Series C
AQN has 100 redeemable preferred shares, Series C issued and outstanding. The preferred shares are mandatorily redeemable in 2031 for C$53,400 per share and have a contractual cumulative cash dividend paid quarterly until the date of redemption based on a prescribed payment schedule indexed in proportion to the increase in CPI over the term of the shares. The preferred shares, Series C are convertible into common shares at the option of the holder and the Company, at any time after May 20, 2031 and before June 19, 2031, at a conversion price of C$53,400 per share.
As these shares are mandatorily redeemable for cash, they are classified as liabilities in the consolidated financial statements. The preferred shares, Series C are accounted for under the effective interest method, resulting in accretion of interest expense over the term of the shares. Dividend payments are recorded as a reduction of the preferred shares, Series C carrying value.
Estimated dividend payments due in the next five years and dividend and redemption payments thereafter are as follows:
2023 $ 1,245
2024 1,443
2025 1,459
2026 1,316
2027 1,262
Thereafter to 2031 4,654
Redemption amount 3,943
$ 15,322
Less: amounts representing interest (3,250)
$ 12,072
Less current portion (1,245)
$ 10,827
(i)Hook up fees
Hook up fees result from the collection from customers of funds for installation and connection to the utility's infrastructure. The fees are refundable as allowed under the facilities’ regulatory agreement.
(j)Contingent development support obligations
The Company provides credit support necessary for the continued development and construction of its equity investees' wind and solar power electric development projects and infrastructure development projects. The contingent development support obligations represent the fair value of the support provided (note 8(c)).
12.Other long-term liabilities (continued)
(k)Note payable to related party
In 2020, a subsidiary of the Company made a tax equity investment into Altavista Solar Subco, LLC, an equity investee of the Company and indirect owner of the Altavista Solar Project. Following the closing of the construction financing facility for the Altavista Solar Project, certain excess funds were distributed to the Company and in return the Company issued a promissory note payable of $30,493 to Altavista Solar Subco, LLC. The promissory note bears an interest rate of 0.675%, compounded annually. The note was repaid in full during the second quarter of 2021.
In 2021, a subsidiary of the Company made a tax equity investment into New Market Solar Investco, LLC, an equity investee of the Company and indirect owner of the New Market Solar Project (note 8(c)). Following the closing of the construction financing facility for the New Market Solar Project, certain excess funds were distributed to the Company and in return the Company issued a promissory note of $25,808 payable to New Market Solar Investco, LLC. The promissory note bears an interest rate of 4% annually and has a maturity date of December 16, 2031.

v3.23.1

Shareholders' capital
12 Months Ended

Dec. 31, 2022

Equity [Abstract]

Shareholders' capital Shareholders’ capital
(a)Common shares
Number of common shares
2022 2021
Common shares, beginning of year 671,960,276 597,142,219
Public offering 2,861,709 67,611,465
Dividend reinvestment plan 7,676,666 6,184,686
Exercise of share-based awards (c) 1,115,398 1,020,020
Conversion of convertible debentures 754 1,886
Common shares, end of year 683,614,803 671,960,276
Authorized
AQN is authorized to issue an unlimited number of common shares. The holders of the common shares are entitled to dividends if, as and when declared by the board of directors of AQN (the “Board”); to one vote per share at meetings of the holders of common shares; and upon liquidation, dissolution or winding up of AQN to receive pro rata the remaining property and assets of AQN, subject to the rights of any shares having priority over the common shares.
The Company has a shareholders’ rights plan (the “Rights Plan”), which expires in 2025. Under the Rights Plan, one right is issued with each issued share of the Company. The rights remain attached to the shares and are not exercisable or separable unless one or more certain specified events occur. If a person or group acting in concert acquires 20 percent or more of the outstanding shares (subject to certain exceptions) of the Company, the rights will entitle the holders thereof (other than the acquiring person or group) to purchase shares at a 50 percent discount from the then-current market price. The rights provided under the Rights Plan are not triggered by any person making a “Permitted Bid”, as defined in the Rights Plan.
(i)Public offering
On November 8, 2021, AQN issued 44,080,000 common shares at a price of $14.63 (C$18.15)per share for total gross proceeds of $642,664 (C$800,052) before issuance costs of $26,173 (C$32,583), which AQN intends to use to partially finance the Kentucky Power Transaction; provided that, in the short-term, prior to the closing of the Kentucky Power Transaction, the Company has used the net proceeds to repay certain indebtedness of AQN and its subsidiaries (note 3(b)). Forward contracts were used to manage the Canadian dollar risk (note 24(b)(iv)).
13.Shareholders’ capital (continued)
(a) Common shares (continued)
(ii)At-the-market equity program
On August 15, 2022, AQN re-established its at-the-market equity program (“ATM program”) which allows the Company to issue up to $500,000 (or the equivalent in Canadian dollars) of common shares from treasury to the public from time to time, at the Company's discretion, at the prevailing market price when issued on the Toronto Stock Exchange (“TSX”), the New York Stock Exchange (“NYSE”), or any other existing trading market for the common shares of the Company in Canada or the United States. During the year ended December 31, 2022, the Company issued 2,861,709 common shares under the ATM program at an average price of $13.94 per common share for gross proceeds of $38,923 ($38,534 net of commissions). Other related costs were $558.
The Company has issued since the inception of the ATM program in 2019 a cumulative total of 36,814,536 common shares at an average price of $15.00 per share for gross proceeds of $551,086 ($544,295 net of commissions). Other related costs, primarily related to the establishment and subsequent re-establishments of the ATM program, were $4,843.
(iii)Dividend reinvestment plan
The Company has a common shareholder dividend reinvestment plan, which, when the plan is active, provides an opportunity for holders of AQN’s common shares who reside in Canada, the United States, or, subject to AQN’s consent, other jurisdictions, to reinvest the cash dividends paid on their common shares in additional common shares which, at AQN’s election, are either purchased on the open market or newly issued from treasury. Effective March 3, 2022, common shares purchased under the plan were issued at a 3% discount (previously at 5%) to the prevailing market price (as determined in accordance with the terms of the plan). Subsequent to year-end, AQN issued an additional 4,370,289 common shares under the dividend reinvestment plan. Effective March 16, 2023, AQN suspended the dividend reinvestment plan. Dividends will only be paid in cash while the reinvestment plan is suspended.
(b)Preferred shares
AQN is authorized to issue an unlimited number of preferred shares, issuable in one or more series, containing terms and conditions as approved by the Board.
The Company has the following preferred shares, Series A and preferred shares, Series D issued and outstanding as at December 31, 2022 and 2021:
Preferred shares Number of shares Price per share Carrying amount C$ Carrying amount $
Series A 4,800,000 C$ 25 C$ 116,546 $ 100,463
Series D 4,000,000 C$ 25 C$ 97,259 $ 83,836
$ 184,299
The holders of preferred shares, Series A are entitled to receive quarterly fixed cumulative preferential cash dividends, if, as and when declared by the Board. The dividend for each year up to, but excluding, December 31, 2023 will be an annual amount of C$1.2905 per share. The Series A dividend rate will reset on December 31, 2023 and every five years thereafter at a rate equal to the then five-year Government of Canada bond yield plus 2.94%. The preferred shares, Series A are redeemable at C$25 per share at the option of the Company on December 31, 2023 and every fifth year thereafter. The holders of preferred shares, Series A have the right to convert their shares into cumulative floating rate preferred shares, Series B, subject to certain conditions, on December 31, 2023, and every fifth year thereafter.
The holders of preferred shares, Series D are entitled to receive fixed cumulative preferential dividends as and when declared by the Board at an annual amount of C$1.2728 per share for each year up to, but excluding, March 31, 2024. The Series D dividend will reset on March 31, 2024 and every five years thereafter at a rate equal to the then five-year Government of Canada bond plus 3.28%. The preferred shares, Series D are redeemable at C$25 per share at the option of the Company on March 31, 2024 and every fifth year thereafter. The holders of preferred shares, Series D have the right to convert their shares into cumulative floating rate preferred shares, Series E, subject to certain conditions, on March 31, 2024, and every fifth year thereafter.
13.Shareholders’ capital (continued)
(b)Preferred shares (continued)
The Company has 100 redeemable preferred shares, Series C issued and outstanding. The mandatorily redeemable preferred shares, Series C are recorded as a liability on the consolidated balance sheets as they are mandatorily redeemable for cash (note 12(h)).
(c)Share-based compensation
For the year ended December 31, 2022, AQN recorded $10,920 (2021 - $8,395) in total share-based compensation expense as follows:
2022 2021
Share options $ 980 $ 939
Director deferred share units 960 821
Employee share purchase 562 592
Performance and restricted share units 8,418 6,043
Total share-based compensation $ 10,920 $ 8,395
The compensation expense is recorded with operating expenses in the consolidated statements of operations. The portion of share-based compensation costs capitalized as cost of construction is insignificant.
As of December 31, 2022, total unrecognized compensation costs related to non-vested share-based awards was $10,732 and is expected to be recognized over a period of 1.8 years.
(i)Share option plan
The Company’s share option plan (the “Plan”) permits the grant of share options to officers, directors, employees and selected service providers. The aggregate number of shares that may be reserved for issuance under the Plan must not exceed 8% of the number of shares outstanding at the time the options are granted.
The number of shares subject to each option, the option price, the expiration date, the vesting and other terms and conditions relating to each option shall be determined by the Board (or the compensation committee of the Board (“Compensation Committee”)) from time to time. Dividends on the underlying shares do not accumulate during the vesting period. Option holders may elect to surrender any portion of the vested options that is then exercisable in exchange for the “In-the-Money Amount”. In accordance with the Plan, the “In-The-Money Amount” represents the excess, if any, of the market price of a share at such time over the option price, in each case such “In-the-Money Amount” being payable by the Company in cash or common shares at the election of the Company. As the Company does not expect to settle these instruments in cash, these options are accounted for as equity awards.
The Compensation Committee may accelerate the vesting of the unvested options then held by the optionee at the Compensation Committee's discretion. In the event that the Company restates its financial results, any unpaid or unexercised options may be cancelled at the discretion of the Compensation Committee in accordance with the terms of the Company's clawback policy.
The estimated fair value of options, including the effect of estimated forfeitures, is recognized as expense on a straight-line basis over the options’ vesting periods while ensuring that the cumulative amount of compensation cost recognized at least equals the value of the vested portion of the award at that date. The Company determines the fair value of options granted using the Black-Scholes option-pricing model. The risk-free interest rate is based on the zero-coupon Canada Government bond with a similar term to the expected life of the options at the grant date. Expected volatility was estimated based on the historical volatility of the Company’s common shares. The expected life was based on experience to date. The dividend yield rate was based upon recent historical dividends paid on AQN common shares.
13.Shareholders’ capital (continued)
(c)Share-based compensation (continued)
(ii)Share option plan (continued)
The following assumptions were used in determining the fair value of share options granted:
2022 2021
Risk-free interest rate 1.9 % 1.1 %
Expected volatility 23 % 23 %
Expected dividend yield 4.3 % 4.1 %
Expected life 5.50 years 5.50 years
Weighted average grant date fair value per option C$ 2.44 C$ 2.46

Share option activity during the years is as follows:
Number of
awards Weighted
average
exercise
price Weighted
average
remaining
contractual
term (years) Aggregate
intrinsic
value
Balance, January 1, 2021 2,110,448 C$ 15.45 6.55 C$ 11,604
Granted 437,006 19.64 7.22 —
Exercised (506,926) 13.92 5.95 1,453
Forfeited — — — —
Balance, December 31, 2021 2,040,528 C$ 15.45 6.11 C$ 3,145
Granted 646,090 19.11 7.22 —
Exercised (40,074) 13.92 5.95 103
Forfeited (19,764) 19.11 — —
Balance, December 31, 2022 2,626,780 C$ 16.02 5.63 C$ —
Exercisable, December 31, 2022 2,052,946 C$ 17.35 5.63 C$ —
(iii)Employee share purchase plan
Under the Company’s ESPP, eligible employees may have a portion of their earnings withheld to be used to purchase the Company’s common shares. The Company will match 20% of the employee contribution amount for the first five thousand dollars per employee contributed annually and 10% of the employee contribution amount for contributions over five thousand dollars up to ten thousand dollars annually. Common shares purchased through the Company match portion shall not be eligible for sale by the participant for a period of one year following the purchase date on which such shares were acquired. At the Company’s option, the common shares may be (i) issued to participants from treasury at the average share price or (ii) acquired on behalf of participants by purchases through the facilities of the TSX or NYSE by an independent broker. The aggregate number of common shares reserved for issuance from treasury by AQN under the ESPP shall not exceed 4,000,000 common shares.
13.Shareholders’ capital (continued)
(c)Share-based compensation (continued)
(iii)Employee share purchase plan (continued)
The Company uses the fair value based method to measure the compensation expense related to the Company’s contribution. For the year ended December 31, 2022, a total of 414,338 common shares (2021 - 355,096 ) were issued to employees under the ESPP.
(iv)Director's deferred share units
Under the Company’s DSU plan, non-employee directors of the Company may elect annually to receive all or any portion of their compensation in DSUs in lieu of cash compensation. Directors’ fees are paid on a quarterly basis and at the time of each payment of fees, the applicable amount is converted to DSUs. A DSU has a value equal to one of the Company’s common shares. Dividends accumulate in the DSU account and are converted to DSUs based on the market value of the shares on that date. DSUs cannot be redeemed until the director retires, resigns, or otherwise leaves the Board. The DSUs provide for settlement in cash or common shares at the election of the Company. As the Company does not expect to settle these instruments in cash, these options are accounted for as equity awards. For the year ended December 31, 2022, a total of 120,513 DSUs (2021 - 73,467) were issued and 5,176 DSUs (2021 - 87,582 ) were settled in exchange for 2,403 common shares issued from treasury, and 2,773 DSUs were settled at their cash value as payment for tax withholding related to the settlement of the awards. As of December 31, 2022, 645,714 (2021 - 530,378) DSUs were outstanding pursuant to the election of the directors to defer a percentage of their director’s fee in the form of DSUs. The aggregate number of common shares reserved for issuance from treasury by AQN under the DSU plan shall not exceed 1,000,000 common shares.
(v)Performance and restricted share units
The Company offers a PSU and RSU plan to its employees as part of the Company’s long-term incentive program. PSUs have been granted annually for three-year overlapping performance cycles. The PSUs vest at the end of the three-year cycle and are calculated based on established performance criteria. At the end of the three-year performance periods, the number of common shares issued can range from 2.5% to 237% of the number of PSUs granted. RSU vesting conditions and dates vary by grant and are outlined in each award letter. RSUs are not subject to performance criteria. Dividends accumulating during the vesting period are converted to PSUs and RSUs based on the market value of the shares on that date and are recorded in equity as the dividends are declared. None of the PSUs or RSUs have voting rights. Any PSUs or RSUs not vested at the end of a performance period will expire. The PSUs and RSUs provide for settlement in cash or common shares at the election of the Company. As the Company does not expect to settle these instruments in cash, these units are accounted for as equity awards. The aggregate number of common shares reserved for issuance from treasury by AQN under the PSU and RSU plan shall not exceed 7,000,000 common shares.
Compensation expense associated with PSUs is recognized rateably over the performance period. Achievement of the performance criteria is estimated at the consolidated balance sheet dates. Compensation cost recognized is adjusted to reflect the performance conditions estimated to date.
13.Shareholders’ capital (continued)
(c)Share-based compensation (continued)
(v)Performance and restricted share units (continued)
A summary of the PSUs and RSUs follows:
Number of awards Weighted
average
grant-date
fair value Weighted
average
remaining
contractual
term (years) Aggregate
intrinsic
value
Balance, January 1, 2021 2,721,207 C$ 16.58 0.93 C$ 54,560
Granted, including dividends 805,433 19.94 2.77 12,881
Exercised (865,067) 13.79 — 17,005
Forfeited (217,901) 18.64 — 3,981
Balance, December 31, 2021 2,443,672 C$ 18.07 1.72 C$ 44,646
Granted, including dividends 1,090,457 17.99 2.00 17,524
Exercised (1,221,620) 12.62 — 23,636
Forfeited (202,799) 18.94 — 418
Balance, December 31, 2022 2,109,710 C$ 18.38 1.76 C$ 18,608
Exercisable, December 31, 2022 769,458 C$ 18.70 0.10 C$ 6,787
(vi)Bonus deferral RSUs
Eligible employees have the option to receive a portion or all of their annual bonus payment in RSUs in lieu of cash. These RSUs provide for settlement in shares, and therefore these RSUs are accounted for as equity awards. The RSUs granted are 100% vested and, therefore, compensation expense associated with these RSUs is recognized immediately upon issuance.
During the year ended December, 31, 2022, 55,445 (2021 - 56,686) bonus deferral RSUs were granted to employees of the Company. In addition, the Company settled 178,368 (2021 - 152,564) bonus deferral RSUs in exchange for 82,886 (2021 - 70,571) common shares issued from treasury, and 95,482 (2021- 81,993) RSUs were settled at their cash value as payment for tax withholdings related to the settlement of the RSUs. As of December 31, 2022, 158,486 (2021 - 281,411) bonus deferral RSUs were outstanding.

v3.23.1

Accumulated other comprehensive income (loss)
12 Months Ended

Dec. 31, 2022

Accumulated Other Comprehensive Income (Loss), Net of Tax [Abstract]

Accumulated other comprehensive income (loss) Accumulated other comprehensive income (loss)
AOCI consists of the following balances, net of tax:
Foreign currency cumulative translation Unrealized gain on cash flow hedges Pension and post-employment actuarial changes Total
Balance, January 1, 2021 $ (39,725) $ 50,817 $ (33,599) $ (22,507)
Other comprehensive income (loss) (25,982) (97,103) 32,247 (90,838)
Amounts reclassified from AOCI to the consolidated statement of operations (4,288) 42,772 9,804 48,288
Net current period OCI $ (30,270) $ (54,331) $ 42,051 $ (42,550)
OCI attributable to the non-controlling interests (249) — — (249)
Net current period OCI attributable to shareholders of AQN $ (30,519) $ (54,331) $ 42,051 $ (42,799)
Amount reclassified from AOCI to non-controlling interest (6,371) — — (6,371)
Balance, December 31, 2021 $ (76,615) $ (3,514) $ 8,452 $ (71,677)
Other comprehensive income (loss) (18,013) (128,838) 23,722 (123,129)
Amounts reclassified from AOCI to the consolidated statement of operations (5,489) 34,543 4,039 33,093
Net current period OCI $ (23,502) (94,295) 27,761 $ (90,036)
OCI attributable to the non-controlling interests 1,650 — — 1,650
Net current period OCI attributable to shareholders of AQN $ (21,852) (94,295) 27,761 $ (88,386)
Balance, December 31, 2022 $ (98,467) $ (97,809) $ 36,213 $ (160,063)
Amounts reclassified from AOCI for foreign currency cumulative translation affected interest expense and derivative gain (loss); those for unrealized gain (loss) on cash flow hedges affected revenue from non-regulated energy sales, interest expense and derivative gain (loss) while those for pension and post-employment actuarial changes affected pension and post-employment non-service costs.

v3.23.1

Dividends
12 Months Ended

Dec. 31, 2022

Disclosure Cash Dividends [Abstract]

Dividends Dividends
All dividends of the Company are made on a discretionary basis as determined by the Board. The Company declares and pays the dividends on its common shares in U.S. dollars. Dividends declared were as follows:
2022 2021
Dividend Dividend per share Dividend Dividend per share
Common shares $ 486,043 $ 0.7130 $ 423,023 $ 0.6669
Preferred shares, Series A C$ 6,194 C$ 1.2905 C$ 6,194 C$ 1.2905
Preferred shares, Series D C$ 5,091 C$ 1.2728 C$ 5,091 C$ 1.2728

v3.23.1

Related party transactions
12 Months Ended

Dec. 31, 2022

Related Party Transactions [Abstract]

Related party transactions Related party transactions
(a)Equity-method investments
The Company provides administrative and development services to its equity-method investees and is reimbursed for incurred costs. To that effect, during 2022, the Company charged its equity-method investees $63,861 (2021 - $25,778). Additionally, Liberty Development JV Inc., an equity-method investee (note 8(c)) provides development services to the Company on specified projects, for which it earns a development fee upon reaching certain milestones. During the year, the development fees charged to the Company were $12,628 (2021 - $2,036).
Investment and acquisition transactions with equity-method investments are described in note 8(c). In addition, during 2021, the Company paid $1,500 to Abengoa S.A. (“Abengoa”) to purchase all of Abengoa's interests in the AAGES, AAGES Development Canada Inc., and AAGES Development Spain, S.A. joint ventures. The assets acquired for AAGES Development Spain S.A. included project development assets for $2,662 and working capital of $1,507. The loan at that date between the Company and AAGES Development Spain S.A. of $3,089 was treated as additional consideration paid to acquire the partnership.
In 2020, the Company issued a promissory note of $30,493 payable to Altavista Solar Subco, LLC, an equity investee of the Company at the time. The note was repaid in full during the second quarter of 2021. During the fourth quarter of 2021, the Company issued a promissory note of $25,808 payable to New Market Solar Investco, LLC, an equity investee of the Company (note 12(k)).
(b)Non-controlling interest and redeemable non-controlling interest held by related party
Non-controlling interest and redeemable non-controlling interest held by related party are described in note 17.
(c) Transactions with Atlantica
During 2021, the Company sold Colombian solar assets to Atlantica for consideration of $23,863, with a gain on sale of $878, and contingent consideration of $2,600. The contingency was resolved in 2022 and, as a result, an additional gain of $1,200 was recognized.
The above related party transactions have been recorded at the exchange amounts agreed to by the parties to the transactions.

v3.23.1

Non-controlling Interests and Redeemable non-controlling Interest
12 Months Ended

Dec. 31, 2022

Noncontrolling Interest [Abstract]

Non-controlling interests and redeemable non-controlling interests Non-controlling interests and redeemable non-controlling interests
Net effect attributable to non-controlling interests for the years ended December 31 consists of the following:
2022 2021
HLBV and other adjustments attributable to:
Non-controlling interests - tax equity partnership units $ 108,695 $ 88,417
Non-controlling interests - redeemable tax equity partnership units 6,298 6,902
Other net earnings attributable to:
Non-controlling interests (3,670) (5,682)
$ 111,323 $ 89,637
Redeemable non-controlling interest, held by related party (15,157) (10,435)
Net effect of non-controlling interests
$ 96,166 $ 79,202
The non-controlling tax equity investors (“tax equity partnership units”) in the Company's U.S. wind power and solar power generating facilities are entitled to allocations of earnings, tax attributes and cash flows in accordance with contractual agreements. The share of earnings attributable to the non-controlling interest holders in these subsidiaries is calculated using the HLBV method of accounting as described in note 1(s).
17.Non-controlling interests and redeemable non-controlling interests (continued)
Non-controlling interests
Non-controlling interests - tax equity partnership units (a) Other non-controlling interests (b) Non-controlling interests held by related parties (c)
2022 2021 2022 2021 2022 2021
Opening balance $ 1,377,117 $ 388,253 $ 64,807 $ 11,234 $ 81,158 $ 59,125
Net earnings attributable to NCI (105,371) (87,422) 345 3,354 — —
Contributions received, net 6,182 1,058,929 267,515 51,451 — 39,376
Dividends and distributions declared (40,086) (11,795) — (1,021) (20,978) (17,793)
Repurchase of non-controlling interest (12,249) — — — — —
Non-controlling interest assumed on asset acquisition — 29,141 — — — —
OCI 15 11 695 (211) (2,358) 450
Closing balance $ 1,225,608 $ 1,377,117 $ 333,362 $ 64,807 $ 57,822 $ 81,158
(a)     Non-controlling interests - tax equity partnership units
The Company obtained control of the three Mid-West Wind Facilities, Sugar Creek Wind Facility and Maverick Creek Wind Facility in 2021 (notes 3(d) and 3(f)), assuming non-controlling interest of $29,141. Post acquisition in 2021, third-party tax equity investors funded $530,880, $380,829 and $147,914, to the Mid-West Wind Facilities, the Sugar Creek Wind Facility and the Maverick Creek Wind Facility, respectively, in exchange for Class A partnership units in the entities.
(b)     Other non-controlling interests
On December 29, 2022, the Company sold a 49% non-controlling interest in three operating wind facilities in the United States totalling 551 MW of installed capacity: the Odell Wind Facility in Minnesota, the Deerfield Wind Facility in Michigan and the Sugar Creek Wind Facility in Illinois. The consideration of $277,500 was recorded as an increase to non-controlling interest, except for a portion of $5,000, which is subject to refund if some conditions are met and as such was recorded as redeemable non-controlling interest.
In January 2021, the Company sold a 32% interest in Eco Acquisitionco SpA, the holding company through which AQN's interest in ESSAL is held, to a third party for consideration of $51,750. This represents an interest of 30% in the aggregate interest in ESSAL, which was reflected by a corresponding increase in non-controlling interest. This transaction resulted in no gain or loss. Following this transaction, AQN indirectly owns approximately 64% of the outstanding shares of ESSAL and continues to consolidate ESSAL's operations.
(c)     Non-controlling interest held by related parties
In November 2021, Liberty Development JV Inc. invested $39,376 in Algonquin (AY Holdco) B.V., a consolidated subsidiary of the Company. In May 2019, AYES Canada acquired an interest in a consolidated subsidiary of the Company for $96,752 (C$130,103) (note 8(b)). The investment by AYES Canada and Liberty Development JV Inc. are presented as a non-controlling interest held by related parties.
17.Non-controlling interests and redeemable non-controlling interests (continued)
Redeemable non-controlling interests
Non-controlling interests in subsidiaries that are redeemable upon the occurrence of uncertain events not solely within AQN’s control are classified as temporary equity on the consolidated balance sheets. If the redemption is probable or currently redeemable, the Company records the instruments at their redemption value. Redemption is not considered probable as of December 31, 2022.
Liberty Global Energy Solutions (note 8(c)), an equity investee of the Company, has a secured credit facility in the amount of $306,500 maturing on January 26, 2024. It is collateralized through a pledge of Atlantica ordinary shares held by AY Holdings. A collateral shortfall would occur if the net obligation (as defined in the credit agreement) would equal or exceed 50% of the market value of such Atlantica shares, in which case the lenders would have the right to sell Atlantica shares to eliminate the collateral shortfall. The Liberty Global Energy Solutions secured credit facility is repayable on demand if Atlantica ceases to be a public company or if certain other events are announced or completed that could restrict AY Holdings’ ability to sell or transfer its Atlantica ordinary shares. Liberty Global Energy Solutions has a preference share ownership in AY Holdings which AQN reflects as redeemable non-controlling interest held by related party.
Changes in redeemable non-controlling interests are as follows:
Redeemable non-controlling interests held by related party Redeemable non-controlling interests
2022 2021 2022 2021
Opening balance $ 306,537 $ 306,316 $ 12,989 $ 20,859
Net earnings attributable to NCI 15,157 10,435 (6,298) (6,902)
Contributions, net of costs — — 5,000 —
Dividends and distributions declared (13,838) (10,214) (171) (968)
Closing balance $ 307,856 $ 306,537 $ 11,520 $ 12,989

v3.23.1

Income taxes
12 Months Ended

Dec. 31, 2022

Income Tax Disclosure [Abstract]

Income taxes Income taxes
The provision for income taxes in the consolidated statements of operations represents an effective tax rate different than the Canadian enacted statutory rate of 26.5% (2021 - 26.5%). The differences are as follows:
2022 2021
Expected income tax expense at Canadian statutory rate $ (97,962) $ 37,691
Increase (decrease) resulting from:
Effect of differences in tax rates on transactions in and within foreign jurisdictions and change in tax rates (55,315) (47,600)
Adjustments from investments carried at fair value 51,314 2,709
Non-controlling interests share of income 30,025 25,135
Change in valuation allowance 41,702 (118)
Non-deductible acquisition costs 1,341 3,733
Acquisition related state deferred tax adjustments 5,998 —
Capital gain rate differential on disposal of renewable assets (7,340) —
Tax credits (18,440) (49,415)
Adjustment relating to prior periods (1,390) 1,333
Deferred income taxes on regulated income recorded as regulatory assets (2,155) (3,807)
Amortization and settlement of excess deferred income tax (14,855) (16,778)
Other 5,564 3,692
Income tax recovery $ (61,513) $ (43,425)
18.Income taxes (continued)
For the years ended December 31, 2022 and 2021, earnings (loss) before income taxes consist of the following:
2022 2021
Canada (1)
$ (363,050) $ (60,848)
U.S. (37,322) 153,719
Other regions 30,704 49,361
$ (369,668) $ 142,232
(1) Inclusive of fair value gain (loss) on investments carried at fair value (note 8)

Income tax expense (recovery) attributable to income (loss) consists of:
Current Deferred Total
Year ended December 31, 2022
Canada $ 4,184 $ (74,595) $ (70,411)
United States 1,579 6,183 7,762
Other regions 2,080 (944) 1,136
$ 7,843 $ (69,356) $ (61,513)
Year ended December 31, 2021
Canada $ 4,560 $ (33,993) $ (29,433)
United States 1,024 (19,772) (18,748)
Other regions 1,653 3,103 4,756
$ 7,237 $ (50,662) $ (43,425)
18.Income taxes (continued)
The tax effect of temporary differences between the financial statement carrying amounts of assets and liabilities and their respective tax bases that give rise to significant portions of the deferred tax assets and deferred tax liabilities as of December 31, 2022 and 2021 are presented below:
2022 2021
Deferred tax assets:
Non-capital loss, investment tax credits, currently non-deductible interest expenses, and financing costs $ 878,000 $ 761,666
Pension and OPEB 16,845 46,580
Environmental obligation 12,118 15,271
Regulatory liabilities 156,285 166,939
Other 61,917 64,460
Total deferred income tax assets $ 1,125,165 $ 1,054,916
Less: valuation allowance (107,583) (27,471)
Total deferred tax assets $ 1,017,582 $ 1,027,445
Deferred tax liabilities:
Property, plant and equipment $ 846,331 $ 782,829
Outside basis differentials 315,581 412,665
Regulatory accounts 303,059 300,072
Other 33,834 30,471
Total deferred tax liabilities $ 1,498,805 $ 1,526,037
Net deferred tax liabilities $ (481,223) $ (498,592)
Consolidated balance sheets classification:
Deferred tax assets $ 84,416 $ 31,595
Deferred tax liabilities (565,639) (530,187)
Net deferred tax liabilities $ (481,223) $ (498,592)
The valuation allowance for deferred tax assets as of December 31, 2022 was $107,583 (2021 - $27,471). The valuation allowance primarily relates to operating losses that, in the judgment of management, are not more likely than not to be realized. In assessing the realizability of deferred tax assets, management considers whether it is more likely than not that some portion or all of the deferred tax assets will not be realized. The ultimate realization of deferred tax assets is dependent upon the generation of future taxable income during the periods in which those temporary differences become deductible. Management considers the scheduled reversal of deferred tax liabilities (including the impact of available carryback and carryforward periods), projected future taxable income, and tax-planning strategies in making this assessment. The amount of the deferred tax asset considered realizable, however, could be adjusted if estimates of future taxable income during the carryforward period are reduced or increased or if objective negative evidence in the form of cumulative losses is no longer present and additional weight is given to subjective evidence such as Management projections for growth.

Primarily as a result of the impairment charges discussed in notes 5 and 8(c), the U.S. entities in the Renewable Energy Group, which have historically been in an overall deferred tax liability position, are in an overall deferred tax asset position as at December 31, 2022. In the course of assessing the U.S. deferred tax assets in the Renewable Energy Group, management concluded that, during the fourth quarter of 2022, it was no longer probable that the Renewable Energy Group would generate sufficient taxable income to realize the benefit of the deferred tax assets of such group. AQN’s conclusion is based on the balance of all available positive and negative evidence applicable to the Renewable Energy Group, including material impairment charges recorded on certain assets, insufficient taxable temporary differences to allow the full utilization of the deferred tax asset, insufficient forecasted taxable income and a historical 3 year cumulative loss position.
18.Income taxes (continued)
The following table illustrates the annual movement in the deferred tax valuation allowance:
2022 2021
Beginning balance $ 27,471 $ 29,824
Charged to income tax expense (recovery) 41,702 (118)
Charged (reduction) to OCI 40,613 (1,707)
Reductions to other accounts (2,203) (528)
Ending balance $ 107,583 $ 27,471
As of December 31, 2022, the Company had non-capital losses carried forward and tax credits available to reduce future years' taxable income, which expire as follows:
Non-capital loss carryforward and credits 2023—2027 2028+ Total
Canada $ 3,261 $ 728,529 $ 731,790
US 9,962 1,707,139 1,717,101
Total non-capital loss carryforward $ 13,223 $ 2,435,668 $ 2,448,891
Tax credits $ 4,428 $ 151,676 $ 156,104
The Company has provided for deferred income taxes for the estimated tax cost of distributed earnings of certain of its subsidiaries. Deferred income taxes have not been provided on approximately $824,052 of undistributed earnings of certain foreign subsidiaries, as the Company has concluded that such earnings are indefinitely reinvested and should not give rise to additional tax liabilities. A determination of the amount of the unrecognized tax liability relating to the remittance of such undistributed earnings is not practicable.

v3.23.1

Other net losses
12 Months Ended

Dec. 31, 2022

Other Income and Expenses [Abstract]

Other net losses Other net losses
Other net losses consist of the following:
2022 2021
Acquisition and transition-related costs $ 17,442 $ 14,507
Other (a) 3,949 8,442
$ 21,391 $ 22,949
(a)Other
Other losses primarily consist of costs pertaining to a condemnation proceeding, and miscellaneous asset write-downs, net of miscellaneous gains. Other losses in 2021 also included an adjustment to a regulatory liability pertaining to the true-up of prior period tracking accounts.

v3.23.1

Basic and diluted net earnings (loss) per share
12 Months Ended

Dec. 31, 2022

Earnings Per Share, Basic and Diluted EPS [Abstract]

Basic and diluted net earnings (loss) per share Basic and diluted net earnings (loss) per share
Basic and diluted earnings per share have been calculated on the basis of net earnings attributable to the common shareholders of the Company and the weighted average number of common shares and bonus deferral restricted share units outstanding. Diluted net earnings per share is computed using the weighted-average number of common shares, additional shares issued subsequent to year-end under the dividend reinvestment plan, PSUs, RSUs and DSUs outstanding during the year and, if dilutive, potential incremental common shares related to the convertible debentures or resulting from the application of the treasury stock method to outstanding share options and Green Equity Units (note 9(c)).
The reconciliation of the net earnings and the weighted average shares used in the computation of basic and diluted earnings per share are as follows:
2022 2021
Net earnings (loss) attributable to shareholders of AQN $ (211,989) $ 264,859
Preferred shares, Series A dividend 4,786 4,942
Preferred shares, Series D dividend 3,934 4,061
Net earnings (loss) attributable to common shareholders of AQN – basic and diluted $ (220,709) $ 255,856
Weighted average number of shares
Basic 677,862,207 622,347,677
Effect of dilutive securities — 6,600,185
Diluted 677,862,207 628,947,862
This calculation of diluted shares excludes the potential impact of the Green Equity Units and all potential incremental shares that may become issuable pursuant to outstanding securities of the Company for the year ended December 31, 2022, as they are antidilutive. The common shares potentially issuable for the year ended December 31, 2021, as a result of 437,006 share options are excluded from this calculation as they are anti-dilutive.

v3.23.1

Segmented information
12 Months Ended

Dec. 31, 2022

Segment Reporting [Abstract]

Segmented information Segmented information
The Company is managed under two primary business units consisting of the Regulated Services Group and the Renewable Energy Group. The two business units are the two segments of the Company.
The Regulated Services Group, the Company's regulated operating unit, owns and operates a portfolio of electric, water distribution and wastewater collection, and natural gas utility systems and transmission operations in the United States, Canada, Bermuda and Chile; the Renewable Energy Group, the Company's non-regulated operating unit, owns and operates, or has investments in, a diversified portfolio of renewable and thermal energy generation assets.
For purposes of evaluating the performance of the business units, the Company allocates the realized portion of any gains or losses on financial instruments to the specific business units. Dividend income from Atlantica and AYES Canada are included in the operations of the Renewable Energy Group, while interest income from SAWS is included in the operations of the Regulated Services Group. Equity method gains and losses are included in the operations of the Regulated Services Group or Renewable Energy Group based on the nature of the activities of the investees. The change in value of investments carried at fair value and unrealized portion of any gains or losses on derivative instruments not designated in a hedging relationship are not considered in management’s evaluation of divisional performance and are therefore allocated and reported under corporate.

Year ended December 31, 2022
Regulated Services Group Renewable Energy Group Corporate Total
Revenue (1)(2)
$ 2,328,536 $ 350,939 $ — $ 2,679,475
Other revenue 55,732 28,447 1,501 85,680
Fuel, power and water purchased 824,670 41,826 — 866,496
Net revenue 1,559,598 337,560 1,501 1,898,659
Operating expenses 736,515 114,463 511 851,489
Administrative expenses 46,484 26,424 7,324 80,232
Depreciation and amortization 317,300 137,203 1,017 455,520
Asset impairment expense — 159,568 — 159,568
Loss on foreign exchange — — 13,833 13,833
459,299 (100,098) (21,184) 338,017
Gain on sale of renewable assets — 64,028 — 64,028
Operating income (loss) 459,299 (36,070) (21,184) 402,045
Interest expense (113,482) (64,285) (100,807) (278,574)
Income (loss) from long-term investments 21,884 15,254 (502,344) (465,206)
Other (14,765) (570) (12,598) (27,933)
Earnings (loss) before income taxes $ 352,936 $ (85,671) $ (636,933) $ (369,668)
Property, plant and equipment $ 8,554,938 $ 3,360,687 $ 29,260 $ 11,944,885
Investments carried at fair value 1,984 1,342,223 — 1,344,207
Equity-method investees 56,199 310,103 15,500 381,802
Total assets 12,109,575 5,251,933 266,105 17,627,613
Capital expenditures $ 908,676 $ 180,348 $ — $ 1,089,024
(1) Renewable Energy Group revenue includes $63,717 related to net hedging loss from energy derivative contracts and availability credits for the year ended December 31, 2022 that do not represent revenue recognized from contracts with customers.
(2) Regulated Services Group revenue includes $21,640 related to alternative revenue programs for the year ended December 31, 2022 that do not represent revenue recognized from contracts with customers.
21.Segmented information (continued)

Year ended December 31, 2021
Regulated Services Group Renewable Energy Group Corporate Total
Revenue (1)(2)
$ 1,944,171 $ 256,633 $ — $ 2,200,804
Other revenue 53,441 18,339 1,558 73,338
Fuel and power purchased 682,602 31,313 — 713,915
Net revenue 1,315,010 243,659 1,558 1,560,227
Operating expenses 597,850 104,262 16 702,128
Administrative expenses 37,179 28,298 1,249 66,726
Depreciation and amortization 280,452 121,414 1,097 402,963
Loss on foreign exchange — — 4,371 4,371
399,529 (10,315) (5,175) 384,039
Gain on sale of renewable assets — 29,063 — 29,063
Operating income (loss) 399,529 18,748 (5,175) 413,102
Interest expense (93,411) (71,598) (44,545) (209,554)
Income (loss) from long-term investments 18,306 84,046 (128,809) (26,457)
Other (24,177) (2,956) (7,726) (34,859)
Earnings (loss) before income taxes $ 300,247 $ 28,240 $ (186,255) $ 142,232
Property, plant and equipment $ 7,394,151 $ 3,615,915 $ 32,380 $ 11,042,446
Investments carried at fair value 2,296 1,846,160 — 1,848,456
Equity-method investees 37,492 375,460 20,898 433,850
Total assets 10,524,466 6,123,888 149,149 16,797,503
Capital expenditures $ 998,855 $ 338,637 $ 7,553 $ 1,345,045
(1) Renewable Energy Group revenue includes $57,018 related to net hedging loss from energy derivative contracts for the year ended December 31, 2021 that do not represent revenue recognized from contracts with customers.
(2) Regulated Services Group revenue includes $19,043 related to alternative revenue programs for the year ended December 31, 2021 that do not represent revenue recognized from contracts with customers.
The majority of non-regulated energy sales are earned from contracts with large public utilities. The Company has sought to mitigate its credit risk by selling energy to large utilities in various North American locations. None of the utilities contribute more than 10% of total revenue.
21.Segmented information (continued)
AQN operates in the independent power and utility industries in the United States, Canada and other regions. Information on operations by geographic area is as follows:
2022 2021
Revenue
United States $ 2,232,959 $ 1,790,539
Canada 175,005 157,854
Other regions 357,191 325,749
$ 2,765,155 $ 2,274,142
Property, plant and equipment
United States $ 10,351,736 $ 9,464,716
Canada 848,560 882,454
Other regions 744,589 695,276
$ 11,944,885 $ 11,042,446
Intangible assets
United States $ 18,818 $ 23,575
Canada 19,038 21,780
Other regions 58,827 59,761
$ 96,683 $ 105,116
Revenue is attributed to the regions based on the location of the underlying generating and utility facilities.

v3.23.1

Commitments and contingencies
12 Months Ended

Dec. 31, 2022

Commitments and Contingencies Disclosure [Abstract]

Commitments and contingencies Commitments and contingencies
(a)Contingencies
AQN and its subsidiaries are involved in various claims and litigation arising out of the ordinary course and conduct of its business. Although such matters cannot be predicted with certainty, management does not consider AQN’s exposure to such litigation to be material to these consolidated financial statements. Accruals for any contingencies related to these items are recorded in the consolidated financial statements at the time it is concluded that its occurrence is probable and the related liability is estimable.
Condemnation expropriation proceedings
On January 7, 2016, the Town of Apple Valley filed a lawsuit seeking to condemn the utility assets of Liberty Utilities (Apple Valley Ranchos Water) Corp. (“Liberty Apple Valley”). On May 7, 2021, the Court issued a Tentative Statement of Decision denying the Town of Apple Valley’s attempt to take the Apple Valley Water System by eminent domain. The ruling confirmed that Liberty Apple Valley’s continued ownership and operation of the water system is in the best interest of the community. On October 14, 2021, the Court issued the Final Statement of Decision. The Court signed and entered an Order of Dismissal and Judgment on November 12, 2021. On January 7, 2022, the Town filed a notice of appeal of the judgment entered by the Court. On August 2, 2022, the Court issued a ruling awarding Liberty Apple Valley approximately $13,222 in attorney’s fees and litigation costs. The Town filed a notice of appeal of the fee award on August 22, 2022. The Town’s appeal of the condemnation judgment and fee award have been consolidated into one appellate docket. The Company has not recorded the possible recovery of these attorney’s fees and litigation costs.
Mountain View fire
On November 17, 2020, a wildfire now known as the Mountain View Fire occurred in the territory of Liberty Utilities (CalPeco Electric) LLC ("Liberty CalPeco"). The cause of the fire remains under investigation, and CAL FIRE has not yet released its final report. There are currently 17 active lawsuits that name certain subsidiaries of the Company as defendants in connection with the Mountain View Fire, as well as one non-litigation claim brought by the U.S. Department of Agriculture seeking reimbursement for alleged fire suppression costs. Twelve lawsuits are brought by groups of individual plaintiffs alleging causes of action including negligence, inverse condemnation, nuisance, trespass, and violations of Cal. Pub. Util. Code 2106 and Cal. Health and Safety Code 13007 (one of these twelve lawsuits also alleges the wrongful death of an individual and various subrogation claims on behalf of insurance companies). In another lawsuit, County of Mono, Antelope Valley Fire Protection District, Toiyabe Indian Health Project, and Bridgeport Indian Colony allege similar causes of action and seek damages for fire suppression costs, law enforcement costs, property and infrastructure damage, and other costs. In four other lawsuits, insurance companies allege inverse condemnation and negligence and seek recovery of amounts paid and to be paid to their insureds. The likelihood of success in these lawsuits cannot be reasonably predicted. Liberty CalPeco intends to vigorously defend them. The Company has wildfire liability insurance that is expected to apply up to applicable policy limits.
(b)Commitments
In addition to the commitments related to the proposed acquisitions and development projects disclosed in notes 3(b) and 8, the following significant commitments exist as of December 31, 2022.
AQN has outstanding purchase commitments for power purchases, natural gas supply and service agreements, service agreements, capital project commitments and land easements.
22.Commitments and contingencies (continued)
(b)Commitments (continued)
Detailed below are estimates of future commitments under these arrangements:
Year 1 Year 2 Year 3 Year 4 Year 5 Thereafter Total
Power purchase (i) $ 89,846 $ 32,490 $ 32,726 $ 12,274 $ 12,520 $ 142,586 $ 322,442
Natural gas supply and service agreements (ii) 113,775 81,719 57,014 40,372 31,457 188,138 512,475
Service agreements 67,477 57,886 55,835 49,596 46,511 298,516 575,821
Capital projects 7,163 — — — — — 7,163
Land easements 13,295 13,316 13,503 13,667 13,837 463,785 531,403
Total $ 291,556 $ 185,411 $ 159,078 $ 115,909 $ 104,325 $ 1,093,025 $ 1,949,304
(i) Power purchase: AQN’s electric distribution facilities have commitments to purchase physical quantities of power for load serving requirements. The commitment amounts included in the table above are based on market prices as of December 31, 2022. However, the effects of purchased power unit cost adjustments are mitigated through a purchased power rate-adjustment mechanism.
(ii) Natural gas supply and service agreements: AQN’s natural gas distribution facilities and thermal generation facilities have commitments to purchase physical quantities of natural gas under contracts for purposes of load serving requirements and of generating power.

v3.23.1

Non-cash operating items
12 Months Ended

Dec. 31, 2022

Disclosure Changes In Non Cash Operating Items [Abstract]

Non-cash operating items Non-cash operating items
The changes in non-cash operating items consist of the following:
2022 2021
Accounts receivable $ (124,631) $ (56,751)
Fuel and natural gas in storage (21,140) (43,642)
Supplies and consumables inventory (24,088) 445
Income taxes recoverable 549 (3,025)
Prepaid expenses (4,269) (1,189)
Accounts payable 24,395 (33,399)
Accrued liabilities 127,076 31,845
Current income tax liability (2,741) 4,363
Asset retirements and environmental obligations (22,342) (1,185)
Net regulatory assets and liabilities (174,427) (419,484)
$ (221,618) $ (522,022)

v3.23.1

Financial instruments
12 Months Ended

Dec. 31, 2022

Fair Value Disclosures [Abstract]

Financial instruments Financial instruments
(a)Fair value of financial instruments
December 31, 2022 Carrying
amount Fair
value Level 1 Level 2 Level 3
Long-term investments carried at fair value $ 1,344,207 $ 1,344,207 $ 1,270,138 $ — $ 74,083
Development loans and other receivables 53,680 50,300 — 50,300 —
Derivative instruments:
Energy contracts not designated as cash flow hedge 393 393 — — 393
Interest rate swap designated as a hedge 69,188 69,188 — 69,188 —
Interest rate cap not designated as a hedge 2,659 2,659 — 2,659 —
Congestion revenue rights not designated as a cash flow hedge 10,110 10,110 — — 10,110
Cross currency swap designated as a net investment hedge 1,267 1,267 — 1,267 —
Commodity contracts for regulated operations 283 283 — 283 —
Total derivative instruments 83,900 83,900 — 73,397 10,503
Total financial assets $ 1,481,787 $ 1,478,407 $ 1,270,138 $ 123,697 $ 84,586
Long-term debt $ 7,512,017 $ 6,699,031 $ 2,623,628 $ 4,075,403 $ —
Notes payable to related party 25,808 15,180 — 15,180 —
Convertible debentures 245 276 276 — —
Preferred shares, Series C 12,072 11,675 — 11,675 —
Derivative instruments:
Energy contracts designated as a cash flow hedge 120,284 120,284 — — 120,284
Energy contracts not designated as a cash flow hedge 8,617 8,617 — — 8,617
Cross-currency swap designated as a net investment hedge 24,371 24,371 — 24,371 —
Cross currency swap designated as a cash flow hedge 15,435 15,435 — 15,435 —
Commodity contracts for regulated operations 1,614 1,614 — 1,614 —
Total derivative instruments 170,321 170,321 — 41,420 128,901
Total financial liabilities $ 7,720,463 $ 6,896,483 $ 2,623,904 $ 4,143,678 $ 128,901
24.Financial instruments (continued)
(a)Fair value of financial instruments (continued)
December 31, 2021 Carrying
amount Fair
value Level 1 Level 2 Level 3
Long-term investment carried at fair value $ 1,848,456 $ 1,848,456 $ 1,753,210 $ — $ 95,246
Development loans and other receivables 32,261 33,286 — 33,286 —
Derivative instruments:
Energy contracts designated as a cash flow hedge 15,362 15,362 — — 15,362
Interest rate swap designated as a hedge 1,581 1,581 — 1,581 —
Cross-currency swap designated as a net investment hedge 1,958 1,958 — 1,958 —
Commodity contracts for regulated operations 1,721 1,721 — 1,721 —
Total derivative instruments 20,622 20,622 — 5,260 15,362
Total financial assets $ 1,901,339 $ 1,902,364 $ 1,753,210 $ 38,546 $ 110,608
Long-term debt $ 6,211,375 $ 6,543,933 $ 2,418,580 $ 4,125,352 $ —
Notes payable to related party 25,808 25,808 — 25,808 —
Convertible debentures 277 519 519 — —
Preferred shares, Series C 13,348 14,580 — 14,580 —
Derivative instruments:
Energy contracts designated as a cash flow hedge 60,462 60,462 — — 60,462
Energy contracts not designated as a cash flow hedge 1,169 1,169 — — 1,169
Cross-currency swap designated as a net investment hedge 50,258 50,258 — 50,258 —
Interest rate swaps designated as a hedge 7,008 7,008 — 7,008 —
Commodity contracts for regulated operations 1,348 1,348 — 1,348 —
Total derivative instruments 120,245 120,245 — 58,614 61,631
Total financial liabilities $ 6,371,053 $ 6,705,085 $ 2,419,099 $ 4,224,354 $ 61,631
The Company has determined that the carrying value of its short-term financial assets and liabilities approximates fair value as of December 31, 2022 and 2021 due to the short-term maturity of these instruments.
24.Financial instruments (continued)
(a)Fair value of financial instruments (continued)
The fair value of the investment in Atlantica (level 1) is measured at the closing price on the NASDAQ stock exchange.
The fair value of development loans and other receivables (level 2) is determined using a discounted cash flow method, using estimated current market rates for similar instruments adjusted for estimated credit risk as determined by management.
The Company’s level 1 fair value of long-term debt is measured at the closing price on the NYSE and the Canadian over-the-counter closing price. The Company’s level 2 fair value of long-term debt at fixed interest rates, notes payable to related party and preferred shares Series C has been determined using a discounted cash flow method and current interest rates. The Company's level 2 fair value of convertible debentures has been determined as the greater of their face value and the quoted value of AQN's common shares on a converted basis.
The Company’s level 2 fair value derivative instruments primarily consist of swaps, options, rights, caps, subscription agreements and forward physical derivatives where market data for pricing inputs are observable. Level 2 pricing inputs are obtained from various market indices and utilize discounting based on quoted interest rate curves, which are observable in the marketplace.
The Company’s level 3 instruments consist of energy contracts for electricity sales, congestion revenue rights ("CRRs") and the fair value of the Company's investment in AYES Canada. The significant unobservable inputs used in the fair value measurement of energy contracts are the internally developed forward market prices ranging from $23.32 to $109.91 with a weighted average of $44.76 as of December 31, 2022. The weighted average forward market prices are developed based on the quantity of energy expected to be sold monthly and the expected forward price during that month. The change in the fair value of the energy contracts is detailed in notes 24(b)(ii) and 24(b)(iv). The significant unobservable inputs used in the fair value measurement of CRRs are recent CRR auction prices ranging from $nil to $23.20 with a weighted average of $7.83 as at December 31, 2022. The fair value of the investment in AYES Canada is determined using a discounted cash flow approach combined with a binomial tree approach. The significant unobservable inputs used in the fair value measurement of the Company's AYES Canada investment are the expected cash flows, the discount rates applied to these cash flows ranging from 8.00% to 8.50% with a weighted average of 8.34%, and the expected volatility of Atlantica's share price ranging from 26.99% to 34.89% as of December 31, 2022. Significant increases (decreases) in expected cash flows or increases (decreases) in discount rate in isolation would have resulted in a significantly lower (higher) fair value measurement.
(b)Derivative instruments
Derivative instruments are recognized on the consolidated balance sheets as either assets or liabilities and measured at fair value at each reporting period.
(i)Commodity derivatives – regulated accounting
The Company uses derivative financial instruments to reduce the cash flow variability associated with the purchase price for a portion of future natural gas purchases associated with its regulated natural gas and electric service territories. The Company’s strategy is to minimize fluctuations in natural gas sale prices to regulated customers.
The following are commodity volumes, in dekatherms (“dths”), associated with the above derivative contracts:
2022
Financial contracts: Swaps
1,687,217
Options 35,824
1,723,041
24.Financial instruments (continued)
(b)Derivative instruments (continued)
(i)Commodity derivatives – regulated accounting (continued)
The accounting for these derivative instruments is subject to guidance for rate regulated enterprises. Therefore, the fair value of these derivatives is recorded as current or long-term assets and liabilities, with offsetting positions recorded as regulatory assets and regulatory liabilities in the consolidated balance sheets. Most of the gains or losses on the settlement of these contracts are included in the calculation of the fuel and commodity costs adjustments (note 7(a)). As a result, the changes in fair value of these natural gas derivative contracts and their offsetting adjustment to regulatory assets and liabilities had no earnings impact.

(ii)Cash flow hedges
The Company reduces the price risk on the expected future sale of power generation by entering into the following long-term energy derivative contracts. Upon the acquisition of the Sugar Creek Wind Facility in 2021 (note 3(f)), the Company redesignated a long-term energy derivative contract to mitigate the price risk on the expected future sale of power generation. The fair value of the derivative on the redesignation date will be amortized into earnings over the remaining life of the contract.
Notional quantity
(MW-hrs) Expiry Receive average
prices (per MW-hr) Pay floating price
(per MW-hr)
4,059,905 September 2030 $24.54 Illinois Hub
413,620 December 2028 $29.15 PJM Western HUB
1,977,766 December 2027 $22.05 NI HUB
1,665,318 December 2027 $36.46 ERCORT North HUB

The Company is party to two interest rate swap contracts as cash flow hedges to mitigate the risk that interest rates will increase over the life of certain term loan facilities. Under the terms of the interest rate swap contracts, the Company has fixed its interest rate expense on such term loan facilities. The fair value of the derivative on the designation date is amortized into earnings over the remaining life of the contract.
The Company is party to a forward-starting interest rate swap in order to reduce the interest rate risk related to the quarterly interest payments between July 1, 2024 and July 1, 2029 on the $350,000 subordinated unsecured notes. The Company designated the entire notional amount of the pay-variable and receive-fixed interest rate swaps as a hedge of the future quarterly variable-rate interest payments associated with the subordinated unsecured notes.
In January 2022, the Company entered into a cross-currency interest rate swap, coterminous with the Canadian Notes, to effectively convert the C$400,000 Canadian Offering into U.S. dollars. The change in the carrying amount of the Canadian Notes due to changes in spot exchange rates is recognized each period in the consolidated statements of operations as loss (gain) on foreign exchange. The Company designated the entire notional amount of the cross-currency fixed-for-fixed interest rate swap as a hedge of the foreign currency exposure related to cash flows for the interest and principal repayments on the Canadian Notes. An offsetting portion of the AOCI balance related to changes in fair value of the cross-currency fixed-for-fixed interest rate swap attributable to changes in the spot exchange rates is also immediately reclassified into the consolidated statements of operations as an offsetting (gain) loss on foreign exchange.
24.Financial instruments (continued)
(b)Derivative instruments (continued)
(ii)Cash flow hedges (continued)
The following table summarizes OCI attributable to derivative financial instruments designated as a cash flow hedge:
2022 2021
Effective portion of cash flow hedge $ (128,838) $ (97,103)
Amortization of cash flow hedge (12,180) (2,132)
Amounts reclassified from AOCI 46,723 44,904
OCI attributable to shareholders of AQN $ (94,295) $ (54,331)
The Company expects $32,467 of unrealized losses currently in AOCI to be reclassified, net of taxes into non-regulated energy sales, investment loss, interest expense and derivative gains, respectively, within the next 12 months, as the underlying hedged transactions settle.
(iii)Foreign exchange hedge of net investment in foreign operation
The functional currency of most of AQN's operations is the U.S. dollar. The Company designates obligations denominated in Canadian dollars as a hedge of the foreign currency exposure of its net investment in its Canadian investments and subsidiaries. The related foreign currency transaction gain or loss designated as, and effective as, a hedge of the net investment in a foreign operation is reported in the same manner as the translation adjustment (in OCI) related to the net investment. A foreign currency gain of $2,262 for the year ended December 31, 2022 (2021 - loss of $168) was recorded in OCI.
On May 23, 2019, the Company entered into a cross-currency swap, coterminous with the subordinated unsecured notes issued on such date, to effectively convert the $350,000 U.S. dollar denominated offering into Canadian dollars. The change in the carrying amount of the notes due to changes in spot exchange rates is recognized each period in the consolidated statements of operations as loss (gain) on foreign exchange. The Company designated the entire notional amount of the cross-currency fixed-for-fixed interest rate swap as a hedge of the foreign currency exposure related to cash flows for the interest and principal repayments on the notes. Upon the change in functional currency of AQN to the U.S. dollar on January 1, 2020, this hedge was dedesignated. The OCI related to this hedge will be amortized into earnings in the period that future interest payments affect earnings over the remaining life of the original hedge. The Company redesignated this swap as a hedge of AQN's net investment in its Canadian subsidiaries.
The related foreign currency transaction gain or loss designated as a hedge of the net investment in a foreign operation is reported in the same manner as the translation adjustment (in OCI) related to the net investment. The fair value of the derivative on the redesignation date will be amortized over the remaining life of the original hedge. A foreign currency gain of $22,091 for the year ended December 31, 2022 (2021 - loss of $4,232 was recorded in OCI).
Canadian operations
The Company is exposed to currency fluctuations from its Canadian-based operations. AQN manages this risk primarily through the use of natural hedges by using Canadian long-term debt to finance its Canadian operations and a combination of foreign exchange forward contracts and spot purchases.
The Company’s Canadian operations are determined to have the Canadian dollar as their functional currency and are exposed to currency fluctuations from their U.S. dollar transactions. The Company designates obligations denominated in U.S. dollars as a hedge of the foreign currency exposure of its net investment in its U.S. investments and subsidiaries. The related foreign currency transaction gain or loss designated as, and effective as, a hedge of the net investment in a foreign operation is reported in the same manner as the translation adjustment (in OCI) related to the net investment. A foreign currency loss of $18,561 for the year ended December 31, 2022 (2021 - gain of $1,595) was recorded in OCI.
24.Financial instruments (continued)
(b)Derivative instruments (continued)
(iii)Foreign exchange hedge of net investment in foreign operation (continued)
Canadian operations (continued)
The Company is party to C$300,000 (December 31, 2021 - $500,000) fixed-for-fixed cross-currency cross currency swaps to effectively convert Canadian dollar debentures into U.S. dollars. In February 2022, the Company settled the cross-currency swap related to its C$200,000 (2021 - C$150,000) debenture that was repaid. The Company designated the entire notional amount of the cross-currency fixed-for-fixed interest rate swap and related short-term U.S. dollar payables created by the monthly accruals of the swap settlement as a hedge of the foreign currency exposure of its net investment in the Renewable Energy Group's U.S. operations. The gain or loss related to the fair value changes of the swap and the related foreign currency gains and losses on the U.S. dollar accruals that are designated as, and are effective as, a hedge of the net investment in a foreign operation are reported in the same manner as the translation adjustment (in OCI) related to the net investment. A loss of $11,082 for the year ended December 31, 2022 (2021 - gain of $7,824) was recorded in OCI.
On April 9, 2021, the Renewable Energy Group entered into a fixed-for-fixed cross-currency interest rate swap, coterminous with the senior unsecured debentures issued on such date (note 9(g)), to effectively convert the C$400,000 Canadian-dollar-denominated offering into U.S. dollars. The Renewable Energy Group designated the entire notional amount of the fixed-for-fixed cross-currency interest rate swap and related short-term U.S. dollar payables created by the monthly accruals of the swap settlement as a hedge of the foreign currency exposure of its net investment in the Renewable Energy Group's U.S. operations. The gain or loss related to the fair value changes of the swap and the related foreign currency gains and losses on the U.S. dollar accruals that are designated as, and are effective as, a hedge of the net investment in a foreign operation are reported in the same manner as the translation adjustment (in OCI) related to the net investment. A loss of $13,374 for the year ended December 31, 2022 (2021 - loss of $1,925) was recorded in OCI.
Chilean operations
The Company is exposed to currency fluctuations from its Chilean-based operations. The Company's Chilean operations are determined to have the Chilean peso as their functional currency. Chilean long-term debt used to finance the operations is denominated in Chilean Unidad de Fomento.
(iv)Other derivatives and risk management
In the normal course of business, the Company is exposed to financial risks that potentially impact its operating results. The Company employs risk management strategies with a view to mitigating these risks to the extent possible on a cost-effective basis. Derivative financial instruments are used to manage certain exposures to fluctuations in exchange rates, interest rates and commodity prices. The Company does not enter into derivative financial agreements for speculative purposes. For derivatives that are not designated as hedges, the changes in the fair value are immediately recognized in earnings.

The Company mitigates the volatility of energy congestion charges at the ERCOT transmission grid by entering into CRRs, which as of December 31, 2022 had notional quantity of 1,328,510 MW-hours at prices ranging from $1.58 per MW-hr to $19.06 per MW-hr with a weighted average of $7.80 per MW-hr for January 2023 to April 2025. These CRRs are not designated as an accounting hedge.
On December 17, 2022, the Company entered into an interest rate cap agreement in the amount of $390,000 for the period between January 15, 2023 and January 15, 2024. The Company was party to an interest rate swap to mitigate the interest rate risk related to debt at its Blue Hill Wind Facility. The contract was novated upon the sale of the Blue Hill Wind Facility. The loss recognized on the derivative was recorded as a reduction of the gain on sale of renewable assets on the consolidated statements of operations (note 3(a)).
24.Financial instruments (continued)
(b)Derivative instruments (continued)
(iv)Other derivatives and risk management (continued)
The Company mitigates the price risk on the expected future sale of power generation of one of its solar facilities through a long-term energy derivative contract with a notional quantity of 516,202 MW-hours, a price of $25.15 per MW-hr and expiring in August 2030 as an economic hedge to the price of energy sales. The derivative contract is not designated as an accounting hedge.
During 2021, the Company executed on currency forward contracts to manage the currency exposure to the Canadian dollar shares issuance (note 13(a)). A foreign currency gain of $2,329 was recorded in 2021 as a result of the settlement.
The effects on the consolidated statements of operations of derivative financial instruments not designated as hedges consist of the following:
2022 2021
Unrealized gain (loss) on derivative financial instruments:
Energy derivative contracts $ (945) $ (5,353)
Commodity contracts 185 —
Total unrealized loss on derivative financial instruments $ (760) $ (5,353)
Realized gain (loss) on derivative financial instruments:
Energy derivative contracts $ 6,939 $ (108)
Currency forward contract — 2,329
Interest rate swaps (7,185) —
Total realized gain (loss) on derivative financial instruments $ (246) $ 2,221
Loss on derivative financial instruments not accounted for as hedges (1,006) (3,132)
Amortization of AOCI gains frozen as a result of hedge dedesignation 3,465 3,712
$ 2,459 $ 580
Consolidated statements of operations classification:
Gain on derivative financial instruments $ 4,408 $ 4,403
Gain on foreign exchange — 2,329
Renewable energy sales 5,236 (6,152)
Reduction to gain on sale of renewable assets (7,185) —
$ 2,459 $ 580
24.Financial instruments (continued)
(c)Risk management (continued)
In addition to the risk management strategies described above, the Company manages exposure to risks arising from financial instruments, including credit risk and liquidity risk.
Credit risk
Credit risk is the risk of an unexpected loss if a customer or counterparty to a financial instrument fails to meet its contractual obligations. The Company’s financial instruments that are exposed to concentrations of credit risk are primarily cash and cash equivalents, accounts receivable, notes receivable and derivative instruments. The Company limits its exposure to credit risk with respect to cash equivalents by ensuring available cash is deposited with its senior lenders, all of which have a credit rating of A or better. The Company does not consider the risk associated with the accounts receivable to be significant as the majority of revenue from power generation is earned from large utility customers having a credit rating of Baa2 or better by Moody's, or BBB or higher by S&P, or BBB or higher by DBRS. Revenue is generally invoiced and collected within 45 days.
The remaining revenue is primarily earned by the Regulated Services Group, which consists of electric, water distribution and wastewater, and natural gas utilities in the United States, Canada, Bermuda and Chile. In this regard, the credit risk related to Regulated Services Group accounts receivable balances of $404,258 is spread over hundreds of thousands of customers. The Company has processes in place to monitor and evaluate this risk on an ongoing basis including background credit checks and security deposits from new customers. In addition, most of the Regulators of the Regulated Services Group allow for a reasonable bad debt expense to be incorporated in the rates and therefore recovered from rate payers.
As of December 31, 2022, the Company’s maximum exposure to credit risk for these financial instruments was as follows:
2022
Cash and cash equivalents and restricted cash $ 101,185
Accounts receivable 552,914
Allowance for doubtful accounts (24,857)
Notes receivable 53,680
$ 682,922
In addition, the Company monitors the creditworthiness of the counterparties to its foreign exchange, interest rate, and energy derivative contracts and assesses each counterparty’s ability to perform on the transactions set forth in the contracts. The counterparties consist primarily of financial institutions. This concentration of counterparties may impact the Company’s overall exposure to credit risk, either positively or negatively, in that the counterparties may be similarly affected by changes in economic, regulatory or other conditions.
Liquidity risk
Liquidity risk is the risk that the Company will not be able to meet its financial obligations as they fall due. The Company’s approach to managing liquidity risk is to take steps to ensure, to the extent possible, that it will have sufficient liquidity to meet liabilities when due. As of December 31, 2022, in addition to cash on hand of $57,623, the Company had $2,288,765 available to be drawn on its revolving and term credit facilities. Each of the Company’s revolving credit facilities contain covenants that may limit amounts available to be drawn.
24.Financial instruments (continued)
(c)Risk management (continued)
Liquidity risk (continued)
The Company’s liabilities mature as follows:
Due less
than 1 year Due 2 to 3
years Due 4 to 5
years Due after
5 years Total
Long-term debt obligations $ 1,128,660 $ 404,633 $ 1,984,855 $ 4,019,166 $ 7,537,314
Interest on long-term debt 310,863 447,227 386,560 3,936,205 5,080,855
Purchase obligations 741,888 — — — 741,888
Environmental obligation 9,326 18,084 1,915 19,021 48,346
Advances in aid of construction 1,554 — — 86,992 88,546
Derivative financial instruments:
Cross-currency swap 3,205 5,541 6,279 24,781 39,806
Energy derivative and commodity contracts 29,286 49,865 29,896 21,468 130,515
Contract adjustment payments on Green Equity Units 76,208 37,668 — — 113,876
Other obligations 37,209 6,392 5,080 271,962 320,643
Total obligations $ 2,338,199 $ 969,410 $ 2,414,585 $ 8,379,595 $ 14,101,789

v3.23.1

Comparative figures
12 Months Ended

Dec. 31, 2022

Organization, Consolidation and Presentation of Financial Statements [Abstract]

Comparative figures Comparative figuresCertain of the comparative figures have been reclassified to conform to the consolidated financial statement presentation adopted in the current year.

v3.23.1

Significant accounting policies (Policies)
12 Months Ended

Dec. 31, 2022

Accounting Policies [Abstract]

Basis of preparation Basis of preparationThe accompanying consolidated financial statements and notes have been prepared in accordance with generally accepted accounting principles in the United States (“U.S. GAAP”) and follow disclosure required under Regulation S-X provided by the U.S. Securities and Exchange Commission.

Basis of consolidation Basis of consolidationThe accompanying consolidated financial statements of AQN include the accounts of AQN, its wholly owned subsidiaries and variable interest entities (“VIEs”) where the Company is the primary beneficiary (note 1(m)). Intercompany transactions and balances have been eliminated. Interests in subsidiaries owned by third parties are included in non-controlling interests (note 1(s)).

Business combinations, intangible assets and goodwill Business combinations, intangible assets and goodwill
The Company accounts for acquisitions of entities or assets that meet the definition of a business as business combinations. Business combinations are accounted for using the acquisition method. Assets acquired and liabilities assumed are measured at their fair value at the acquisition date, except for deferred income taxes, which are accounted for as described in note 1(v). Acquisition costs are expensed in the period incurred. When the set of activities does not represent a business, the transaction is accounted for as an asset acquisition and includes acquisition costs.
Intangible assets acquired are recognized separately at fair value if they arise from contractual or other legal rights or are separable. Power sales contracts are amortized on a straight-line basis over the remaining term of the contract ranging from 6 to 25 years from the date of acquisition. Interconnection agreements are amortized on a straight-line basis over their estimated life of 40 years. The majority of the Company's customer relationships are amortized on a straight-line basis over their estimated lives of 25 to 40 years. Certain customer relationships and water rights in Chile as well as brand names are considered indefinite-lived intangibles and are not amortized, but assessed annually for indicators of impairment. Miscellaneous intangibles include renewable energy credits that are purchased by the Company's electric utilities to satisfy renewable portfolio standard obligations. These intangibles are not amortized but are derecognized when remitted to the respective state authority to satisfy the compliance obligation.
Goodwill represents the excess of the purchase price of an acquired business over the fair value of the net assets acquired. Goodwill is generally not included in the rate base on which regulated utilities are allowed to earn a return and is not amortized.
As at September 30 of each year, the Company assesses qualitative and quantitative factors to determine whether it is more likely than not that the fair value of a reporting unit to which goodwill is attributed is less than its carrying amount. If it is more likely than not that a reporting unit’s fair value is less than its carrying amount or if a quantitative assessment is elected, the Company calculates the fair value of the reporting unit. If the carrying amount of the reporting unit as a whole exceeds the reporting unit’s fair value, an impairment charge is recorded in an amount of that excess, limited to the total amount of goodwill allocated to that reporting unit. Goodwill is tested for impairment between annual tests if an event occurs or circumstances change that would more likely than not reduce the fair value of a reporting unit below its carrying amount.

Accounting for rate regulated operations Accounting for rate regulated operations
The operating companies within the Regulated Services Group are subject to rate regulation generally overseen by the regulatory authorities of the jurisdictions in which they operate (the “Regulator”). The Regulator provides the final determination of the rates charged to customers. AQN’s regulated operating companies are accounted for under the principles of U.S. Financial Accounting Standards Board (“FASB”) ASC Topic 980, Regulated Operations (“ASC 980”) except for AQN's Chilean operating company, Empresa de Servicios de Los Lagos S.A. (“ESSAL”), which was acquired in October 2020. The rates that are approved under the Chilean regulatory framework are designed to recover the costs of service of a model water utility. Because the rates are not designed to recover ESSAL's specific costs of service, the utility does not meet the criteria to follow the accounting guidance under ASC 980.
Under ASC 980, regulatory assets and liabilities are recorded to the extent that they represent probable future revenue or expenses associated with certain charges or credits that will be recovered from or refunded to customers through the rate making process. Included in note 7, “Regulatory matters”, are details of regulatory assets and liabilities, and their current regulatory treatment.
In the event the Company determines that its net regulatory assets are not probable of recovery, it would no longer apply the principles of the current accounting guidance for rate regulated enterprises and would be required to record an after-tax, non-cash charge or credit against earnings for any remaining regulatory assets or liabilities. The impact could be material to the Company’s reported financial condition and results of operations.
The U.S. electric, gas and water utilities’ accounts are maintained in accordance with the Uniform System of Accounts prescribed by the Federal Energy Regulatory Commission (“FERC”), the applicable Regulator(s) and National Association of Regulatory Utility Commissioners in the United States. The New Brunswick Gas accounts are maintained in accordance with the New Brunswick Gas Distribution Act Uniform Accounting Regulation.

Cash and cash equivalents Cash and cash equivalentsCash and cash equivalents include all highly liquid instruments with an original maturity of three months or less.

Restricted cash Restricted cashRestricted cash represents reserves and amounts set aside pursuant to requirements of various debt agreements, deposits to be returned back to customers, and certain requirements related to generation and transmission operations. Cash reserves segregated from AQN’s cash balances are maintained in accounts administered by a separate agent and disclosed separately as restricted cash in these consolidated financial statements. AQN cannot access restricted cash without the prior authorization of parties not related to AQN.

Accounts receivable Accounts receivableTrade accounts receivable are recorded at the invoiced amount and do not bear interest. The Company maintains an allowance for doubtful accounts for estimated losses inherent in its accounts receivable portfolio. In establishing the required allowance, management considers historical losses adjusted to take into account current market conditions and customers’ financial condition, the amount of receivables in dispute, future economic conditions and outlook, and the receivables aging and current payment patterns. Account balances are charged against the allowance after all means of collection have been exhausted and the potential for recovery is considered remote. The Company does not have any off-balance sheet credit exposure related to its customers.

Fuel and natural gas in storage Fuel and natural gas in storageFuel and natural gas in storage is reflected at weighted average cost or first-in-first-out as required by regulators and represents fuel, natural gas and liquefied natural gas that will be utilized in the ordinary course of business of the gas utilities and some generating facilities. Existing rate orders and other contracts allow the Company to pass through the cost of gas purchased directly to the customers along with any applicable authorized delivery surcharge adjustments (note 7(a)). Accordingly, the net realizable value of fuel and gas in storage does not fall below the cost to the Company.

Supplies and consumables inventory Supplies and consumables inventorySupplies and consumables inventory (other than capital spares and rotatable spares, which are included in property, plant and equipment) are charged to inventory when purchased and then capitalized to plant or expensed, as appropriate, when installed, used or upon becoming obsolete. These items are stated at the lower of cost and net realizable value. Through rate orders and the regulatory environment, capitalized construction jobs are recovered through rate base and repair and maintenance expenses are recovered through a cost of service calculation. Accordingly, the cost usually reflects the net realizable value.

Property, plant and equipment Property, plant and equipment
Property, plant and equipment are recorded at cost. Capitalization of development projects begins when management with the relevant authority has authorized and committed to the funding of a project and it is probable that costs will be realized through the use of the asset or ultimate construction and operation of a facility. Project development costs for rate regulated entities, including expenditures for preliminary surveys, plans, investigations, environmental studies, regulatory applications and other costs incurred for the purpose of determining the feasibility of capital expansion projects, are capitalized either as regulatory assets or property, plant and equipment when it is determined that recovery of such costs through regulated revenue of the completed project is probable.
The costs of acquiring or constructing property, plant and equipment include the following: materials, labour, contractor and professional services, construction overhead directly attributable to the capital project (where applicable), interest for non-regulated property and allowance for funds used during construction (“AFUDC”) for regulated property. Where possible, individual components are recorded and depreciated separately in the books and records of the Company. Plant and equipment under finance leases are initially recorded at cost determined as the present value of lease payments to be made over the lease term.
AFUDC represents the cost of borrowed funds and a return on other funds. Under ASC 980, an allowance for funds used during construction projects that are included in rate base is capitalized. This allowance is designed to enable a utility to capitalize financing costs during periods of construction of property subject to rate regulation. For operations that do not apply regulatory accounting, interest related only to debt is capitalized as a cost of construction in accordance with ASC 835, Interest. The interest capitalized that relates to debt reduces interest expense on the consolidated statements of operations. The AFUDC capitalized that relates to equity funds is recorded as interest and other income under income from long-term investments on the consolidated statements of operations.
Improvements that increase or prolong the service life or capacity of an asset are capitalized. Costs incurred for major expenditures or overhauls that occur at regular intervals over the life of an asset are capitalized and depreciated over the related interval. Maintenance and repair costs are expensed as incurred. Grants related to capital expenditures are recorded as a reduction to the cost of assets and are amortized at the rate of the related asset as a reduction to depreciation expense. Grants related to operating expenses such as maintenance and repairs costs are recorded as a reduction of the related expense. Contributions in aid of construction represent amounts contributed by customers, governments and developers to assist with the funding of some or all of the cost of utility capital assets. They also include amounts initially recorded as advances in aid of construction (note 12(c)) once the advance repayment period has expired. These contributions are recorded as a reduction in the cost of utility assets and are amortized at the rate of the related asset as a reduction to depreciation expense.
1.Significant accounting policies (continued)
(j)Property, plant and equipment (continued)

The Company’s depreciation is based on the estimated useful lives of the depreciable assets in each category and is determined using the straight-line method with the exception of certain wind assets, as described below. The ranges of estimated useful lives and the weighted average useful lives are summarized below:
Range of useful lives Weighted average useful lives
2022 2021 2022 2021
Generation
3-60
3-60
33 33
Distribution
1-100
1-100
39 40
Equipment
5-54
5-50
11 11
The Company uses the unit-of-production method for certain components of its wind generating facilities where the useful life of the component is directly related to the amount of production. The benefits of components subject to wear and tear from the power generation process are best reflected through the unit-of-production method. The Company generally uses wind studies prepared by third parties to estimate the total expected production of each component.
In accordance with regulator-approved accounting policies, when depreciable property, plant and equipment of the Regulated Services Group are replaced or retired, the original cost plus any removal costs incurred (net of salvage) are charged to accumulated depreciation with no gain or loss reflected in results of operations. Gains and losses will be charged to results of operations in the future through adjustments to depreciation expense. In the absence of regulator-approved accounting policies, gains and losses on the disposition of property, plant and equipment are charged to earnings as incurred.

Commonly owned facilities Commonly owned facilitiesThe Regulated Services Group owns undivided interests in three electric generating facilities with ownership interest ranging from 7.52% to 60%, with a corresponding share of capacity and generation from the facility used to serve certain of its utility customers. The Company's investment in the undivided interest is recorded as plant in service and recovered through rate base. Commonly owned facilities represent cost of $559,630 (2021 - $557,954) and accumulated depreciation of $75,820 (2021 - $59,857). The Company's share of operating costs is recognized in operating, maintenance and fuel expenditures excluding depreciation expense. Total expenditures incurred on these facilities for the year ended December 31, 2022 were $110,268 (2021 - $143,255).

Impairment of long-lived assets Impairment of long-lived assets
AQN reviews property, plant and equipment and finite-life intangible assets for impairment whenever events or changes in circumstances indicate the carrying amount may not be recoverable.
As at September 30 of each year, the Company assesses qualitative factors to determine whether it is more likely than not that the indefinite-lived intangible is impaired. If it is more likely than not that the indefinite-lived intangible asset is impaired, the Company calculates the fair value of the intangible asset. If the carrying value of the intangible asset exceeds its fair value, the Company recognizes an impairment loss in an amount equal to that excess. Indefinite-life intangibles are tested for impairment between annual tests if an event occurs or circumstances change that would more likely than not reduces the fair value below its carrying amount.
Recoverability of assets expected to be held and used is measured by comparing the carrying amount of an asset to undiscounted expected future cash flows. If the carrying amount exceeds the recoverable amount, the asset is written down to its fair value. During the fourth quarter of 2022, the Company recorded an impairment charge of $159,568 to reduce the carrying value of the Senate Wind Facility and other smaller assets from $259,942 to $100,374 (note 5).
1.Significant accounting policies (continued)

Variable interest entities Variable interest entities
The Company performs analyses to assess whether its operations and investments represent VIEs. To identify potential VIEs, management reviews contracts under leases, long-term purchase power agreements and jointly owned facilities. VIEs for which the Company is deemed the primary beneficiary are consolidated. In circumstances where AQN is not deemed the primary beneficiary, the VIE is not consolidated (note 8).
The Company has equity and notes receivable interests in two power generating facilities. AQN has determined that these entities are considered VIEs mainly based on total equity at risk not being sufficient to permit the legal entity to finance its activities without additional subordinated financial support. The key decisions that affect the generating facilities’ economic performance relate to siting, permitting, technology, construction, operations and maintenance and financing. As AQN has both the power to direct the activities of the entities that most significantly impact its economic performance and the right to receive benefits or the obligation to absorb losses of the entities that could potentially be significant to the entities, the Company is considered the primary beneficiary.

Long-term investments and notes receivable Long-term investments and notes receivable
Investments in which AQN has significant influence but not control are either accounted for using the equity method or at fair value. Equity-method investments are initially measured at cost including transaction costs and interest when applicable. AQN records its share in the income or loss of its equity-method investees in income from long-term investments in the consolidated statements of operations. AQN records in the consolidated statements of operations the fluctuations in the fair value of its investees held at fair value and dividend income when it is declared by the investee.
Notes receivable are financial assets with fixed or determined payments that are not quoted in an active market. Notes receivable are initially recorded at cost, which is generally face value. Subsequent to acquisition, the notes receivable are recorded at amortized cost using the effective interest method. The Company holds these notes receivable as long-term investments and does not intend to sell these instruments prior to maturity. Interest from long-term investments is recorded as earned and when collectability of both the interest and principal are reasonably assured.
If a loss in value of a long-term investment is considered other than temporary, an allowance for impairment on the investment is recorded for the amount of that loss. An allowance on notes receivable is recorded in order to present the net amount expected to be collected on the receivable. This allowance reflects the risk of loss over the remaining contractual life of the asset, taking into consideration historical experience, current conditions, and reasonable and supportable forecasts of future economic conditions. The impairment is measured based on the present value of expected future cash flows discounted at the note’s effective interest rate. During the fourth quarter of 2022, the Renewable Energy Group recorded an impairment charge of $75,910 to reduce the carrying value of its equity investment in the Texas Coastal Wind Facilities (as defined herein) from $282,726 to 206,816 (note 8(c)).

Pension and other post-employment plans Pension and other post-employment plans
The Company has established defined contribution pension plans, defined benefit pension plans, other post-employment benefit (“OPEB”) plans, and supplemental retirement program (“SERP”) plans for its various employee groups. Employer contributions to the defined contribution pension plans are expensed as employees render service. The Company recognizes the funded status of its defined benefit pension plans, OPEB and SERP plans on the consolidated balance sheets. The Company’s expense and liabilities are determined by actuarial valuations, using assumptions that are evaluated annually as of December 31, including discount rates, mortality, assumed rates of return, compensation increases, turnover rates and healthcare cost trend rates. The impact of modifications to those assumptions and modifications to prior services are recorded as actuarial gains and losses in accumulated other comprehensive income (“AOCI”) and amortized to net periodic cost over future periods using the corridor method. When settlements of the Company's pension plans occur, the Company recognizes associated gains or losses immediately in earnings if the cost of all settlements during the year is greater than the sum of the service cost and interest cost components of the pension plan for the year. The amount recognized is a pro rata portion of the gains and losses in AOCI equal to the percentage reduction in the projected benefit obligation as a result of the settlement.
The costs of the Company’s pension for employees are expensed over the periods during which employees render service and the service costs are recognized as part of administrative expenses in the consolidated statements of operations. The components of net periodic benefit cost other than the service cost component are included in other net losses in the consolidated statements of operations.

Asset retirement obligations Asset retirement obligationsThe Company recognizes a liability for asset retirement obligations based on the fair value of the liability when incurred, which is generally upon acquisition, during construction or through the normal operation of the asset. Concurrently, the Company also capitalizes an asset retirement cost, equal to the estimated fair value of the asset retirement obligation, by increasing the carrying value of the related long-lived asset. The asset retirement costs are depreciated over the asset’s estimated useful life and are included in depreciation and amortization expense on the consolidated statements of operations. Increases in the asset retirement obligation resulting from the passage of time are recorded as accretion of asset retirement obligation in the consolidated statements of operations. Actual expenditures incurred are charged against the obligation.

Leases Leases
The Company accounts for leases in accordance with ASC Topic 842, Leases. The Company leases land, buildings, vehicles, rail cars, and office equipment for use in its day-to-day operations. The Company has options to extend the lease term of many of its lease agreements, with renewal periods ranging from one to five years. As at the consolidated balance sheet date, the Company is not reasonably certain that these renewal options will be exercised.
The Renewable Energy Group enters into land easement agreements for the operation of its generation facilities. In assessing whether these contracts contain leases, the Company considers whether it has exclusive use of the land. In the majority of situations, the landowner or grantor of the easement still has full access to the land and can use the land in any capacity, as long as it does not interfere with the Company’s operations. Therefore, these land easement agreements do not contain leases. For land easement agreements that provide exclusive access to and use of the land, these agreements meet the definition of a lease and are within the scope of ASC 842.
The right-of-use assets are included in property, plant and equipment while lease liabilities are included in other liabilities on the consolidated balance sheets. The discount rates used in the measurement of the Company's right-of-use assets and liabilities are the discount rates at the date of lease inception. The Company's lease balances as at December 31, 2022 and its expected lease payments for the next five years and thereafter are not significant.

Share-based compensation Share-based compensationThe Company has several share-based compensation plans: a share option plan; an employee share purchase plan (“ESPP”); a deferred share unit (“DSU”) plan; and a restricted share unit (“RSU”) and performance share unit (“PSU”) plan. Equity-classified awards are measured at the grant date fair value of the award. The Company estimates grant date fair value of options using the Black-Scholes option pricing model. The fair value is recognized over the vesting period of the award granted, adjusted for estimated forfeitures. The compensation cost is recorded as administrative expenses in the consolidated statements of operations and additional paid-in capital in equity. Additional paid-in capital is reduced as the awards are exercised, and the amount initially recorded in additional paid-in capital is credited to common shares.

Non-controlling interests Non-controlling interests
Non-controlling interests represent the portion of equity ownership in subsidiaries that is not attributable to the equity holders of AQN. Non-controlling interests are initially recorded at fair value and subsequently adjusted for the proportionate share of earnings and other comprehensive income (“OCI”) attributable to the non-controlling interests and any dividends or distributions paid to the non-controlling interests.
If a transaction results in the acquisition of all, or part, of a non-controlling interest in a consolidated subsidiary, the acquisition of the non-controlling interest is accounted for as an equity transaction. No gain or loss is recognized in net earnings or comprehensive income as a result of changes in the non-controlling interest, unless a change results in the loss of control by the Company.
Certain of the Company’s U.S. based wind and solar businesses are organized as limited liability corporations (“LLCs”) and partnerships and have non-controlling membership equity investors (“tax equity partnership units”, or “Tax Equity Investors”), which are entitled to allocations of earnings, tax attributes and cash flows in accordance with contractual agreements. These LLCs and partnership agreements have liquidation rights and priorities that are different from the underlying percentage ownership interests. In those situations, simply applying the percentage ownership interest to U.S. GAAP net income in order to determine earnings or losses would not accurately represent the income allocation and cash flow distributions that will ultimately be received by the investors. As such, the share of earnings attributable to the non-controlling interest holders in these entities is calculated using the Hypothetical Liquidation at Book Value (“HLBV”) method of accounting (note 17).
The HLBV method uses a balance sheet approach. A calculation is prepared at each balance sheet date to
determine the amount that Tax Equity Investors would receive if an equity investment entity were to liquidate all of its assets and distribute that cash to the investors based on the contractually defined liquidation priorities. The difference between the calculated liquidation distribution amounts at the beginning and the end of the reporting period is the Tax Equity Investors' share of the earnings or losses from the investment for that period.
Equity instruments subject to redemption upon the occurrence of uncertain events not solely within AQN’s control are classified as temporary equity and presented as redeemable non-controlling interests on the consolidated balance sheets. The Company records temporary equity at issuance based on cash received less any transaction costs. As needed, the Company reevaluates the classification of its redeemable instruments, as well as the probability of redemption. If the redemption amount is probable or currently redeemable, the Company records the instruments at their redemption value. Increases or decreases in the carrying amount of a redeemable instrument are recorded within deficit. When the redemption feature lapses or other events cause the classification of an equity instrument as temporary equity to be no longer required, the existing carrying amount of the equity instrument is reclassified to permanent equity at the date of the event that caused the reclassification.

Recognition of revenue Recognition of revenue
Revenue is recognized when control of the promised goods or services is transferred to the Company’s customers in an amount that reflects the consideration the Company expects to be entitled to in exchange for those goods or services.
Refer to note 21, “Segmented information” for details of revenue disaggregation by business units.
1.Significant accounting policies (continued)
(t)Recognition of revenue (continued)
Regulated Services Group revenue
Regulated Services Group revenue derives primarily from the distribution of electricity, water and natural gas.
Revenue related to utility electricity and natural gas sales and distribution is recognized over time as the energy is delivered. At the end of each month, the electricity and natural gas delivered to the customers from the date of their last meter read to the end of the month is estimated and the corresponding unbilled revenue is recorded. These estimates of unbilled revenue and sales are based on the ratio of billable days versus unbilled days, amount of electricity or natural gas procured during that month, historical customer class usage patterns, weather, line loss, unaccounted-for natural gas and current tariffs. Unbilled receivables are typically billed within the next month. Some customers elect to pay their bill on an equal monthly plan.
As a result, in some months cash is received in advance of the delivery of electricity. Deferred revenue is recorded for that amount. The amount of revenue recognized in the period from the balance of deferred revenue is not significant.
Water reclamation and distribution revenue is recognized over time when water is processed or delivered to customers. At the end of each month, the water delivered and wastewater collected from the customers from the date of their last meter read to the end of the month are estimated and the corresponding unbilled revenue is recorded. These estimates of unbilled revenue are based on the ratio of billable days versus unbilled days, amount of water procured and collected during that month, historical customer class usage patterns and current tariffs. Unbilled receivables are typically billed within the next month.
On occasion, a utility is permitted to implement new rates that have not been formally approved by the regulatory commission, which are subject to refund. The Company recognizes revenue based on the interim rate and, if needed, establishes a reserve for amounts that could be refunded based on experience for the jurisdiction in which the rates were implemented.
Revenue for certain of the Company’s regulated utilities is subject to alternative revenue programs approved by their respective regulators. Under these programs, the Company charges approved annual delivery revenue on a systematic basis over the fiscal year. As a result, the difference between delivery revenue calculated based on metered consumption and approved delivery revenue is disclosed as alternative revenue in note 21, “Segmented information” and is recorded as a regulatory asset or liability to reflect future recovery or refund, respectively, from customers (note 7). The amount subsequently billed to customers is recorded as a recovery of the regulatory asset.
Renewable Energy Group revenue
Renewable Energy Group's revenue derives primarily from the sale of electricity, capacity, and renewable energy credits.
Revenue related to the sale of electricity is recognized over time as the electricity is delivered. The electricity represents a single performance obligation that represents a promise to transfer to the customer a series of distinct goods that are substantially the same and that have the same pattern of transfer to the customer.
Revenue related to the sale of capacity is recognized over time as the capacity is provided. The nature of the promise to provide capacity is that of a stand-ready obligation. The capacity is generally expressed in monthly volumes and prices. The capacity represents a single performance obligation that represents a promise to transfer to the customer a series of distinct services that are substantially the same and that have the same pattern of transfer to the customer.
1.Significant accounting policies (continued)
(t)Recognition of revenue (continued)
Renewable Energy Group revenue (continued)
Qualifying renewable energy projects receive renewable energy credits (“RECs”) and solar renewable energy credits (“SRECs”) for the generation and delivery of renewable energy to the power grid. The energy credit certificates represent proof that 1 MW of electricity was generated from an eligible energy source. The RECs and SRECs can be traded and the owner of the RECs or SRECs can claim to have purchased renewable energy. RECs and SRECs are primarily sold under fixed contracts, and revenue for these contracts is recognized at a point in time, upon generation of the associated electricity. Any RECs or SRECs generated above contracted amounts are held in inventory, with the offset recorded as a decrease in operating expenses.
The Company applies the invoicing expedient to the electricity and capacity in the Renewable Energy Group contracts. As such, revenue is recognized at the amount to which the Company has the right to invoice for services performed. Revenue is recorded net of sales taxes.

Foreign currency translation Foreign currency translation
AQN’s reporting currency is the U.S. dollar. Within these consolidated financial statements, the Company denotes any amounts denominated in Canadian dollars with “C$”, in Chilean pesos with “CLP” and in Chilean Unidad de Fomento with “CLF” immediately prior to the stated amounts.
Effective January 1, 2020, the functional currency of AQN, the non-consolidated parent entity, changed from the Canadian dollar to the U.S. dollar based on a balance of facts taking into consideration its operating, financing and investing activities. As a result of the entity's change of functional currency, changes were made to certain hedging relationships to mitigate the remaining Canadian dollar risk (note 24).
The Company’s Canadian operations have the Canadian dollar as their functional currency since the preponderance of operating, financing and investing transactions are denominated in Canadian dollars. Similarly, the Company's Chilean and Bermudian operations' functional currency is the Chilean peso and the Bermudian dollar, respectively. The financial statements of these operations are translated into U.S. dollars using the current rate method, whereby assets and liabilities are translated at the rate prevailing at the balance sheet date, and revenue and expenses are translated using average rates for the period. Unrealized gains or losses arising as a result of the translation of the financial statements of these entities are reported as a component of OCI and are accumulated in a component of equity on the consolidated balance sheets, and are not recorded in income unless there is a complete or substantially complete sale or liquidation of the investment.

Income taxes Income taxes
Income taxes are accounted for using the asset and liability method. Deferred tax assets and liabilities are recognized for the future tax consequences attributable to differences between the financial statement carrying amounts of assets and liabilities and their respective tax bases. Deferred tax assets and liabilities are measured using enacted tax rates expected to apply to taxable income in the years in which those temporary differences are expected to be recovered or settled. A valuation allowance is recorded against deferred tax assets to the extent that it is considered more likely than not that the deferred tax asset will not be realized. The effect on deferred tax assets and liabilities of a change in tax rates is recognized in earnings in the period that includes the date of enactment. Investment tax credits for the rate regulated operations are deferred and amortized as a reduction to income tax expense over the estimated useful lives of the properties. Investment tax credits along with other income tax credits in the non-regulated operations are treated as a reduction to income tax expense in the year the credit arises.
The organizational structure of AQN and its subsidiaries is complex and the related tax interpretations, regulations and legislation in the tax jurisdictions in which they operate are continually changing. As a result, there can be tax matters that have uncertain tax positions. The Company recognizes the effect of income tax positions only if those positions are more likely than not of being sustained. Recognized income tax positions are measured at the largest amount that is greater than 50% likely of being realized. Changes in recognition or measurement are reflected in the period in which the change in judgment occurs.

Financial instruments and derivatives Financial instruments and derivatives
Accounts receivable and notes receivable are measured at amortized cost. Long-term debt and preferred shares, Series C are measured at amortized cost using the effective interest method, adjusted for the amortization or accretion of premiums or discounts.
Transaction costs that are directly attributable to the acquisition of financial assets are accounted for as part of the asset’s carrying value at inception. Transaction costs related to a recognized debt liability are presented in the consolidated balance sheets as a direct deduction from the carrying amount of that debt liability, consistent with debt discounts and premiums. Costs of arranging the Company’s revolving credit facilities and intercompany loans are recorded in other assets. Deferred financing costs, premiums and discounts on long-term debt are amortized using the effective interest method while deferred financing costs relating to the revolving credit facilities and intercompany loans are amortized on a straight-line basis over the term of the respective instrument.
The Company uses derivative financial instruments as one method to manage exposures to fluctuations in exchange rates, interest rates and commodity prices. AQN recognizes all derivative instruments as either assets or liabilities on the consolidated balance sheets at their respective fair values. The fair value recognized on derivative instruments executed with the same counterparty under a master netting arrangement are presented on a gross basis on the consolidated balance sheets. The amounts that could net settle are not significant. The Company applies hedge accounting to some of its financial instruments used to manage its foreign currency risk, interest rate risk and price risk exposures associated with sales of generated electricity.
For derivatives designated in a cash flow hedge relationship, the change in fair value is recognized in OCI.
The amount recognized in AOCI is reclassified to earnings in the same period as the hedged cash flows affect earnings under the same line item in the consolidated statements of operations as the hedged item. If the hedging instrument no longer meets the criteria for hedge accounting, expires or is sold, terminated, exercised, or the designation is revoked, then hedge accounting is discontinued prospectively. The amount remaining in AOCI is transferred to the consolidated statements of operations in the same period that the hedged item affects earnings. If the forecasted transaction is no longer expected to occur, then the balance in AOCI is recognized immediately in earnings.
Foreign currency gain or loss on derivative or financial instruments designated as a hedge of the foreign currency exposure of a net investment in foreign operations that are effective as a hedge is reported in the same manner as the translation adjustment (in OCI) related to the net investment.
The Company’s electric distribution and thermal generation facilities enter into power and natural gas purchase contracts for load serving and generation requirements. These contracts meet the exemption for normal purchase and normal sales and, as such, are not required to be recorded at fair value as derivatives and are accounted for on an accrual basis. Counterparties are evaluated on an ongoing basis for non-performance risk to ensure it does not impact the conclusion with respect to this exemption.

Fair value measurements Fair value measurements
The Company utilizes valuation techniques that maximize the use of observable inputs and minimize the use of unobservable inputs to the extent possible. The Company determines fair value based on assumptions that market participants would use in pricing an asset or liability in the principal or most advantageous market. When considering market participant assumptions in fair value measurements, the following fair value hierarchy distinguishes between observable and unobservable inputs, which are categorized in one of the following levels:
•Level 1 Inputs: Unadjusted quoted prices in active markets for identical assets or liabilities accessible to the reporting entity at the measurement date.
•Level 2 Inputs: Other than quoted prices included in level 1, inputs that are observable for the asset or liability, either directly or indirectly, for substantially the full term of the asset or liability.
•Level 3 Inputs: Unobservable inputs for the asset or liability used to measure fair value to the extent that observable inputs are not available, thereby allowing for situations in which there is little, if any, market activity for the asset or liability at the measurement date.

Commitments and contingencies Commitments and contingenciesLiabilities for loss contingencies arising from environmental remediation, claims, assessments, litigation, fines, penalties and other sources are recorded when it is probable that a liability has been incurred and the amount can be reasonably estimated. Legal costs incurred in connection with loss contingencies are expensed as incurred.

Use of estimates Use of estimatesThe preparation of financial statements requires management to make estimates and assumptions that affect the reported amounts of assets and liabilities and disclosure of contingent assets and liabilities at the date of these consolidated financial statements and the reported amounts of revenue and expenses during the year. Actual results could differ from those estimates. During the years presented, management has made a number of estimates and valuation assumptions, including the useful lives and recoverability of property, plant and equipment, intangible assets and goodwill; the recoverability of notes receivable and long-term investments; the recoverability of deferred tax assets; assessments of unbilled revenue; pension and OPEB obligations; timing effect of regulated assets and liabilities; contingencies related to environmental matters; the fair value of assets and liabilities acquired in a business combination; and the fair value of financial instruments. These estimates and valuation assumptions are based on present conditions and management’s planned course of action, as well as assumptions about future business and economic conditions. Should the underlying valuation assumptions and estimates change, the recorded amounts could change by a material amount.

Recently adopted accounting pronouncements Recently issued accounting pronouncements
(a)Recently adopted accounting pronouncements
The Financial Accounting Standards Board (“FASB”) issued ASU 2021-05, Leases (Topic 842): Lessors — Certain Leases with Variable Lease Payments to address concerns relating to day-one losses for sales-type or direct financing leases with variable payments that do not depend on a reference index or rate. The update amends the lease classification requirements for lessors to align them with past practice under Topic 840, Leases. The adoption of this update did not have an impact on the consolidated financial statements.
The FASB issued ASU 2020-06, Debt — Debt with Conversion and Other Options (Subtopic 470-20) and Derivatives and Hedging — Contracts in Entity's Own Equity (Subtopic 815-40): Accounting for Convertible Instruments and Contracts in an Entity's Own Equity to address the complexity associated with accounting for certain financial instruments with characteristics of liabilities and equity. The number of accounting models for convertible debt instruments and convertible preferred stock is being reduced and the guidance has been amended for the derivatives scope exception for contracts in an entity's own equity to reduce form-over-substance-based accounting conclusions. The adoption of this update did not have an impact on the consolidated financial statements.
The FASB issued ASU 2020-04, Reference Rate Reform (Topic 848): Facilitation of the Effects of Reference Rate Reform on Financial Reporting, which provides optional expedients and exceptions to ease the potential burden in accounting for reference rate reform. The amendments apply to contracts, hedging relationships, and other transactions that reference LIBOR or another reference rate expected to be discontinued because of the reference rate reform. The FASB issued updates to Topic 848 in ASU 2022-06 and 2021-01 to clarify that the scope of Topic 848 includes derivatives affected by the discounting transition and extend the relief in Topic 848 to December 31, 2024, respectively. The adoption of this update did not have an impact on the consolidated financial statements.
(b)Recently issued accounting guidance not yet adopted
The FASB issued ASU 2022-04, Liabilities — Supplier Finance Programs (Subtopic 405-50): Disclosure of Supplier Finance Program Obligations, which require that a buyer in a supplier finance program disclose sufficient information about the program to allow a user of financial statements to understand the program’s nature, activity during the period, changes from period to period, and potential magnitude. The amendments in this update are effective for fiscal years beginning after December 15, 2022, including interim periods within those fiscal years, except for the amendment on roll forward information, which is effective for fiscal years beginning after December 15, 2023. Early adoption is permitted. The Company is currently assessing the relevant disclosure.

v3.23.1

Significant accounting policies (Tables)
12 Months Ended

Dec. 31, 2022

Accounting Policies [Abstract]

Schedule of Estimated Useful Lives of Depreciable Assets The ranges of estimated useful lives and the weighted average useful lives are summarized below:
Range of useful lives Weighted average useful lives
2022 2021 2022 2021
Generation
3-60
3-60
33 33
Distribution
1-100
1-100
39 40
Equipment
5-54
5-50
11 11

v3.23.1

Business acquisitions, development projects and disposition transactions (Tables)
12 Months Ended

Dec. 31, 2022

New York Water Company, Inc

Business Acquisition [Line Items]

Schedule of Allocation of Assets Acquired and Liabilities Assumed The following table summarizes the final allocation of the purchase price to the assets acquired and liabilities assumed when control was obtained.
Working capital $ 4,820
Property, plant and equipment (i) 499,252
Goodwill (ii) 116,254
Regulatory assets (iii) 65,621
Other assets 4,507
Pension and other post-employment benefits (13,402)
Regulatory liabilities (iii) (59,727)
Other liabilities (8,028)
Total net assets acquired $ 609,297
Cash and cash equivalents acquired 49
Total net assets acquired, net of cash and cash equivalents $ 609,248

Mid-West Wind Facilities

Business Acquisition [Line Items]

Schedule of Allocation of Assets Acquired and Liabilities Assumed
The following table summarizes the allocation of the aggregate purchase price to the assets acquired and liabilities assumed at the acquisition dates.
Mid-West Wind
Working capital $ (28,630)
Property, plant and equipment 1,141,884
Long-term debt (789,804)
Asset retirement obligation (27,053)
Deferred tax liability (4,566)
Other liabilities (104,129)
Non-controlling interest (tax equity investors) (29,141)
Total net assets acquired 158,561
Cash and cash equivalents 15,860
Net assets acquired, net of cash and cash equivalents $ 142,701

Altavista Solar Facility

Business Acquisition [Line Items]

Schedule of Allocation of Assets Acquired and Liabilities Assumed
The following table summarizes the allocation of the purchase price to the assets acquired and liabilities assumed at the acquisition date of the solar facility.
Altavista Solar
Working capital $ 870
Property, plant and equipment 138,343
Long-term debt (122,024)
Deferred tax liability (421)
Asset retirement obligation (3,332)
Total net assets acquired 13,436
Cash and cash equivalents 33
Net assets acquired, net of cash and cash equivalents $ 13,403

Maverick Creek and Sugar Creek Wind Facilities

Business Acquisition [Line Items]

Schedule of Allocation of Assets Acquired and Liabilities Assumed
The following table summarizes the allocation of the purchase price to the assets acquired and liabilities assumed at the acquisition date of the two wind facilities. The existing loans between the Company and the partnerships of $87,035 were treated as additional consideration incurred to acquire the partnerships.
Maverick Creek and Sugar Creek
Working capital $ (15,557)
Property, plant and equipment 1,062,613
Long-term debt (855,409)
Asset retirement obligation (23,402)
Deferred tax liability (337)
Derivative instruments 7,575
Total net assets acquired 175,483
Cash and cash equivalents 4,241
Net assets acquired, net of cash and cash equivalents $ 171,242

v3.23.1

Property, plant and equipment (Tables)
12 Months Ended

Dec. 31, 2022

Property, Plant and Equipment [Abstract]

Schedule of Property, Plant and Equipment
Property, plant and equipment consist of the following:
2022
Cost Accumulated depreciation Net book value
Renewable generation facilities $ 4,119,514 $ 1,016,784 $ 3,102,730
Utility plant 8,640,224 990,975 7,649,249
Land 113,153 — 113,153
Equipment 111,707 50,904 60,803
Construction in progress
Generation 196,287 — 196,287
Distribution and transmission 822,663 — 822,663
$ 14,003,548 $ 2,058,663 $ 11,944,885
5.Property, plant and equipment (continued)
2021
Cost Accumulated depreciation Net book value
Renewable generation facilities $ 4,187,197 $ 751,219 $ 3,435,978
Utility plant 7,468,236 780,537 6,687,699
Land 114,821 — 114,821
Equipment 101,971 56,464 45,507
Construction in progress
Generation 148,302 — 148,302
Distribution and transmission 610,139 — 610,139
$ 12,630,666 $ 1,588,220 $ 11,042,446

Schedule of Capitalization of Interest
Interest and AFUDC capitalized to the cost of the assets in 2022 and 2021 are as follows:
2022 2021
Interest capitalized on non-regulated property $ 4,762 $ 3,313
AFUDC capitalized on regulated property:
Allowance for borrowed funds 6,040 3,208
Allowance for equity funds 1,901 829
$ 12,703 $ 7,350

v3.23.1

Intangible assets and goodwill (Tables)
12 Months Ended

Dec. 31, 2022

Goodwill and Intangible Assets Disclosure [Abstract]

Schedule of Intangible Assets
Intangible assets consist of the following:
2022 Cost Accumulated amortization Net book value
Power sales contracts $ 56,926 $ 42,818 $ 14,108
Customer relationships 77,850 13,709 64,141
Interconnection agreements 10,098 1,851 8,247
Other (a)
10,338 151 10,187
$ 155,212 $ 58,529 $ 96,683
2021 Cost Accumulated amortization Net book value
Power sales contracts $ 58,112 $ 43,118 $ 14,994
Customer relationships 78,140 12,337 65,803
Interconnection agreements 15,072 1,721 13,351
Other (a)
10,968 — 10,968
$ 162,292 $ 57,176 $ 105,116
(a) Other includes brand names, water rights and miscellaneous intangibles

Schedule of Goodwill
All goodwill pertains to the Regulated Services Group.
2022 2021
Opening balance $ 1,201,244 $ 1,208,390
Business acquisitions (note 3) 123,751 5,535
Foreign exchange (4,416) (12,681)
Closing balance $ 1,320,579 $ 1,201,244

v3.23.1

Regulatory matters (Tables)
12 Months Ended

Dec. 31, 2022

Regulated Operations [Abstract]

Schedule of Regulatory Assets and Liabilities The following regulatory proceedings were recently completed:
Utility State, Province or Country Regulatory Proceeding Type Details
BELCO Bermuda General rate review
On March 18, 2022, the Regulatory Authority (“RA”) approved an annual increase of $22,800, for a revenue allowance of $224,056 and $226,160 in revenue for 2022 and 2023, respectively. The RA authorized a rate of return of 7.16%, comprised of a 62% equity and an 8.92% return on equity. The new rates are effective from April 1, 2022. In April, 2022, BELCO filed an appeal in the Supreme Court of Bermuda challenging the decisions made by the RA through the recent Retail Tariff Review.
Empire Electric Missouri General Rate Case (GRC) and Securitization
On April 6, 2022, the Missouri Public Service Commission (the "MPSC") approved an annual base rate increase of $35,516, as well as another $4,000 in revenues associated with the Empire Wind Facilities. The new rates became effective in June 2022.

On January 19, 2022, Empire Electric filed a petition for securitization of the costs associated with the impact of the Midwest Extreme Weather Event. On March 21, 2022, Empire Electric filed a petition for securitization of the costs associated with the retirement of the Asbury generating plant. On August 18, 2022, and September 22, 2022, the MPSC issued and amended, respectively, a Report and Order authorizing Empire Electric to securitize approximately $290,383 in qualified extraordinary costs (Midwest Extreme Weather Event), energy transition costs (Asbury) and upfront financing costs associated with the proposed securitization. The amounts authorized by the securitization order are generally consistent with the costs deferred by the Company in relation to these matters. Empire Electric filed an appeal of the MPSC order on November 10, 2022 (note 7(a) and (b)). Briefing of the case is expected to be completed in April 2023.
7.Regulatory matters (continued)

Utility State, Province or Country Regulatory Proceeding Type Details
Empire Electric Kansas GRC
On May 27, 2021, Empire Electric submitted an abbreviated rate review seeking to recover costs associated with the addition of the Empire Wind Facilities, the retirement of Asbury and non-growth related plant investments since the 2019 rate review. In May 2022, the Commission approved the unanimous partial settlement resolving the rate treatment of the Asbury retirement and the non-wind investments resulting in a base rate decrease of $636, and granted Empire Electric's motion to withdraw its request to recover cost associated with the Empire Wind Facilities. New rates became effective in July 2022.
Empire District Gas Company Missouri GRC
In June 2022, the Commission approved an annual increase of $1,000 in base rate revenues. New rates became effective in August 2022.
Empire Electric Oklahoma GRC
On December 29, 2022 the Commission approved a joint stipulation and agreement filed by the Company and Staff authorizing an annual base rate revenue increase of $5,100.
New Brunswick Gas Canada GRC
On November 22, 2021, New Brunswick Gas filed its 2022 general rate application for a revenue decrease based on the Energy & Utilities Board's recent decision authorizing a capital structure of 45% equity and an ROE of 8.5%. In January 2022, New Brunswick Natural Gas appealed the Energy & Utilities Board's cost of capital decision. In May 2022, the Energy & Utilities Board issued a partial decision approving a decrease in annual revenues of $1,041 to become effective in July 2022. In June 2022, the Court of Appeal found in favour of New Brunswick Gas and remanded the cost of capital case back to the Energy & Utilities Board. On December 22, 2022 the Board issued a Final Order and approved an annual revenue increase of $1,265 based on an ROE of 9.8%. New rates became effective January 1, 2023.
Apple Valley Ranchos Water System California GRC
Subsequent to year-end, on February 3, 2023, the Commission issued a Final Order authorizing an annual revenue increase of $1,412. New rates are retroactive to July 1, 2022.
Park Water System California GRC
Subsequent to year-end, on February 3, 2023, the Commission issued a Final Order authorizing an annual revenue increase of $1,105. New rates are retroactive to July 1, 2022.
7.Regulatory matters (continued)
Regulatory assets and liabilities consist of the following:
December 31, 2022 December 31, 2021
Regulatory assets
Fuel and commodity cost adjustments (a) $ 388,294 $ 339,900
Retired generating plant (b) 174,609 185,073
Rate adjustment mechanism (c) 136,198 117,309
Income taxes (d) 97,414 79,472
Deferred capitalized costs (e) 90,121 62,599
Pension and post-employment benefits (f) 80,736 134,287
Environmental remediation (g) 70,529 81,802
Wildfire mitigation and vegetation management (h) 66,156 35,726
Clean energy and other customer programs (i) 28,145 25,857
Asset retirement obligation (j) 27,172 26,810
Debt premium (k) 24,888 34,204
Cost of removal (l) 11,084 —
Rate review costs (m) 9,481 9,167
Long-term maintenance contract (n) 6,504 9,134
Other (o) 60,170 26,285
Total regulatory assets $ 1,271,501 $ 1,167,625
Less: current regulatory assets (190,393) (158,212)
Non-current regulatory assets $ 1,081,108 $ 1,009,413
Regulatory liabilities
Income taxes (d) $ 312,671 $ 295,720
Cost of removal (l) 191,173 191,981
Pension and post-employment benefits (f) 68,085 34,468
Fuel and commodity cost adjustments (a) 24,991 18,175
Clean energy and other customer programs (i) 11,572 14,829
Rate adjustment mechanism (c) 343 3,316
Other 19,347 17,700
Total regulatory liabilities $ 628,182 $ 576,189
Less: current regulatory liabilities (69,865) (65,809)
Non-current regulatory liabilities $ 558,317 $ 510,380
Fuel and commodity cost adjustments
The revenue from the utilities includes a component that is designed to recover the cost of electricity and natural gas through rates charged to customers. To the extent actual costs of power or fuel purchased differ from power or fuel costs recoverable through current rates, that difference is deferred and recorded as a regulatory asset or liability on the consolidated balance sheets. These differences are reflected in adjustments to rates and recorded as an adjustment to cost of electricity and fuel in future periods ranging mostly from 6 to 24 months, subject to regulatory review. Derivatives are often utilized to manage the price risk associated with natural gas purchasing activities in accordance with the expectations of state regulators. The gains and losses associated with these derivatives (note 24(b)(i)) are recoverable through the commodity costs adjustment.
In February 2021, the Company's operations were impacted by extreme winter storm conditions experienced in Texas and parts of the central U.S. (“Midwest Extreme Weather Event”). As a result of the Midwest Extreme Weather Event, the Company incurred incremental commodity costs during the period of record high pricing and elevated consumption. The Company has commodity cost mechanisms that allow for the recovery of prudently incurred expenses.
In early 2022, pursuant to the securitization statute, Empire Electric sought authorization for the issuance of $221,646 in securitized utility tariff bonds associated with the Midwest Extreme Weather Event and $140,774, in securitized utility tariff bonds for its Asbury costs, which included $21,283 in asset retirement obligations, which are estimates of costs that Empire Electric will recover from the Asbury retirement but which have not yet been incurred. On April 27, 2022, the MPSC issued an order consolidating, for purposes of hearing, these two cases regarding the quantum financeable through securitization, which hearing was held the week of June 13, 2022. On August 18, 2022, and September 22, 2022, the MPSC issued and amended, respectively, a Report and Order authorizing Empire Electric to securitize $290,383 in qualified extraordinary costs (Midwest Extreme Weather Event), energy transition costs (Asbury) and upfront financing costs associated with the proposed securitization. The amounts authorized by the securitization order are generally consistent with the costs deferred by the Company in relation to these matters. Empire Electric filed a request for rehearing seeking reconsideration of the MPSC’s denial of recovery of five percent of the Midwest Extreme Weather Event costs, its calculation of accumulated deferred income taxes, and the exclusion of certain carrying charges associated with the Asbury plant, among other issues. On October 12, 2022, the MPSC denied all rehearing motions. Empire Electric appealed to the Missouri Court of Appeals - Western District on November 10, 2022. Briefing of the case is expected to be completed in April 2023.
(b)Retired generating plant
On March 1, 2020, the Company's 200 MW coal generation facility located in Asbury, Missouri, ceased operations. The Company transferred the remaining net book value of Asbury’s plant retired from plant in-service to a regulatory asset. The net book value that may be retained as an asset on the balance sheet for the retired plant is dependent upon amounts that may be recovered through regulated rates, including any return. An impairment charge, if any, would equal the difference between the remaining net book value of the asset and the present value of the future revenues expected from the asset. The ultimate valuation of the regulatory asset will be determined in future commission orders. The Company is also assessing the decommissioning requirements associated with the retirement of the facility.
Per commission orders in its jurisdictions, the Company is required to track the impact of Asbury's retirement on operating and capital expenses in Missouri for consideration in the next rate case. The Company recorded a regulatory liability for the estimated amount of revenues collected from customers for Asbury from March 1, 2020 to May 2022 that AQN determined was probable of refund. This regulatory liability did not include revenues collected related to the return on investment in Asbury as AQN determined that they were not probable of refund to customers based on the relevant facts and circumstances. AQN believes it is probable that the Asbury regulatory liability will be offset for recovery purposes against its unrecovered investment in Asbury and as a result, has netted its regulatory liability against its retired generation facilities regulatory asset.
As noted above under (a) Fuel and commodity cost adjustments, in March 2022, Empire Electric filed petitions for securitization of the impact of the Midwest Extreme Weather Event and the retirement of Asbury.
7.Regulatory matters (continued)
(c)Rate adjustment mechanism
Revenue for CalPeco Electric System, New England Gas System, Midstates Gas system, EnergyNorth Gas System, Granite State Electric System, Peach State Gas System and BELCO is subject to a revenue decoupling mechanism approved by their respective regulator, which allows revenue decoupling from sales. As a result, the difference between delivery revenue calculated based on metered consumption and approved delivery revenue is recorded as a regulatory asset or liability to reflect future recovery or refund, respectively, from customers over periods ranging from one to five years. The revenue from BELCO includes a component that is designed to recover budgeted capital and operating expenses for the current year. To the extent actual capital and operating expenditures are lower than the budgeted amounts, 80% of the shortfall is refundable to customers and is recorded as a regulatory liability. Retroactive rate adjustments for services rendered but to be collected over a period not exceeding 24 months are accrued upon approval of the final order. The difference between New Brunswick Gas' regulated revenues and its regulated cost of service in past years is also recorded as a regulatory asset and is recovered on a straight-line basis over 26 years. The Liberty NY Water System has similar trackers which are recovered over periods ranging from one to two years.
(d)Income taxes
The income taxes regulatory assets and liabilities represent income taxes recoverable through future revenues required to fund flow-through deferred income tax liabilities over the life of the plants and amounts owed to customers for deferred taxes collected at a higher rate than the current statutory rates.
(e)Deferred capitalized costs
Deferred capitalized costs reflect deferred construction costs and fuel-related costs of specific generating facilities of the Empire Electric System. These amounts are being recovered over the life of the plants. The amount also includes capitalized operating and maintenance costs of New Brunswick Gas, and these amounts are being recovered at a rate of 2.43% annually.
In 2020, the Empire Electric System made an election under Missouri law to apply the plant-in-service accounting (“PISA”) regulatory mechanism, which permits the Empire Electric System to defer, on a Missouri jurisdictional basis, 85% of the depreciation expense and carrying costs at the applicable WACC on certain property, plant, and equipment placed in service after the election date and not included in base rates. The portions of regulatory asset balances that are not yet being recovered through rates shall include carrying costs at the WACC, plus applicable federal, state, and local income or excise taxes. Regulatory asset balances included in rate base shall be recovered in rates through a 20-year amortization beginning on the effective date of new rates. The Company recognizes the cost of debt on PISA deferrals as reduction of interest expense. The difference between the WACC and cost of debt will be recognized in revenue when recovery of such deferrals is reflected in customer rates.
(f)Pension and post-employment benefits
To the extent pension and OPEB costs incurred differ from the costs recoverable through current rates, that difference is deferred and recorded as a regulatory asset or liability as approved by the applicable Regulators and is recovered through rates over a period of 3 to 8 years. In addition, the annual movements in AOCI for pension and OPEB for Empire Electric System, Empire Gas Systems, St. Lawrence Gas System and Liberty NY Water System (note 10(a)) are reclassified to regulatory accounts in accordance with ASC 980, Regulated Operations. The balance is recovered through rates consistent with the treatment of OCI under ASC 712, Compensation Non-retirement Post-employment Benefits and ASC 715, Compensation Retirement Benefits. As part of certain business acquisitions, the regulators authorized a regulatory asset or liability being set up for the amounts of pension and post-employment benefits that had not yet been recognized in net periodic cost and were presented as AOCI prior to the acquisition. These balances are recovered through rates over the future service years of the employees (an average of 10 years) or consistent with the treatment of OCI under ASC 712, Compensation Non-retirement Post-employment Benefits and ASC 715, Compensation Retirement Benefits before the transfer to regulatory asset occurred.
7.Regulatory matters (continued)
(g)Environmental remediation
Actual expenditures incurred for the clean-up of certain former natural gas manufacturing facilities (note 12(d)) are recovered through rates over a period of 7 years and are subject to an annual cap.
(h)Wildfire mitigation and vegetation management
The regulatory asset includes incremental wildfire liability insurance premium costs approved for tracking in the Company's California operations as well as the difference between actual and adopted spending related to dead trees program, to prevent future forest fires and general vegetation management. The assets are recovered over two years.
(i)Clean energy and other customer programs
The regulatory asset for clean energy and customer programs includes initiatives related to solar rebate applications processed and resulting rebate-related costs. The amount also includes other energy efficiency programs. The assets are generally included in rate base and recovered over periods of six to ten years.
(j)Asset retirement obligation
Asset retirement obligations are recorded for legally required removal costs of property, plant and equipment. The costs of retirement of assets as well as the on-going liability accretion and asset depreciation expense are expected to be recovered through rates once expenditures are made.
(k)Debt premium
Debt premium on acquired debt is recovered as a component of the weighted average cost of debt.
(l)Cost of removal
Rates charged to customers cover for costs that are expected to be incurred in the future to retire the utility plant. A regulatory liability (or asset) tracks the amounts that have been collected from customers net of costs incurred to date.
(m)Rate review costs
The cost to file, prosecute and defend rate review applications is referred to as rate review costs. These costs are capitalized and amortized over the period of rate recovery granted by the Regulator ranging from one to five years
(n)Long-term maintenance contract
To the extent actual costs of long-term maintenance incurred for one of Empire Electric System's power plants differ from the costs recoverable through current rates, that difference is generally included in rate base and recovered over five years.
(o) Other
The Company’s regulated utilities incur other miscellaneous costs such as storm costs, property taxes, financing costs, and equipment costs, which are probable of recovery under existing mechanisms.

v3.23.1

Long-term investments (Tables)
12 Months Ended

Dec. 31, 2022

Disclosure Long Term Investments And Notes Receivable [Abstract]

Schedule of Long-term Investments
Long-term investments consist of the following:
December 31, 2022 December 31, 2021
Long-term investments carried at fair value
Atlantica (a) $ 1,268,140 $ 1,750,914
Atlantica Yield Energy Solutions Canada Inc. (b) 74,083 95,246
Other 1,984 2,296
$ 1,344,207 $ 1,848,456
Other long-term investments
Equity-method investees (c) $ 381,802 $ 433,850
Development loans receivable from equity-method investees (d) 52,923 31,468
San Antonio Water System and other (e) 27,600 30,508
$ 462,325 $ 495,826

Schedule of Income from Long-term Investments
Fair value change, income (loss) and impairment expense related to long-term investments from the years ended December 31 is as follows:
Year ended December 31,
2022 2021
Fair value gain (loss) on investments carried at fair value
Atlantica $ (482,774) $ (107,030)
Atlantica Yield Energy Solutions Canada Inc. (16,018) (15,915)
Other (333) 526
$ (499,125) $ (122,419)
Dividend and interest income from investments carried at fair value
Atlantica $ 86,664 $ 83,971
Atlantica Yield Energy Solutions Canada Inc. 20,443 17,222
Other 36 330
$ 107,143 $ 101,523
Other long-term investments
Equity method loss (c) $ (21,416) $ (26,337)
Impairment of equity-method investee (c) (75,910) —
Interest and other income 24,102 20,776
$ (73,224) $ (5,561)
Fair value change, income (loss) and impairment expense related to long-term investments $ (465,206) $ (26,457)

(a)Investment in Atlantica
Liberty (AY Holdings) B.V. (“AY Holdings”), an entity controlled and consolidated by AQN, has a share ownership in Atlantica Sustainable Infrastructure PLC (“Atlantica”) of approximately 42% (2021 - 44%). AQN has the flexibility, subject to certain conditions, to increase its ownership of Atlantica up to 48.5%. The total cost for the Atlantica shares as of December 31, 2022 is $1,167,444 (2021 - $1,167,444).
The Company has elected the fair value option under ASC 825, Financial Instruments to account for its investment in Atlantica, with changes in fair value reflected in the consolidated statements of operations.
8.Long-term investments (continued)
(b)Investment in AYES Canada
AQN and Atlantica own Atlantica Yield Energy Solutions Canada Inc. (“AYES Canada”), a vehicle to channel co-investment opportunities in which Atlantica holds the majority of voting rights. AYES Canada invested in Windlectric Inc. (“Windlectric”). The investment by AYES Canada in Windlectric is presented as a non-controlling interest held by a related party (notes 17).
AYES Canada is considered to be a VIE based on the disproportionate voting and economic interests of the shareholders. Atlantica is considered to be the primary beneficiary of AYES Canada. Accordingly, AQN's investment in AYES Canada is considered an equity method investment. Under the AYES Canada shareholders agreement, AQN has the option to exchange approximately 3,500,000 shares of AYES Canada into ordinary shares of Atlantica on a one-for-one basis, subject to certain conditions. Consistent with the treatment of the Atlantica shares, the Company has elected the fair value option under ASC 825, Financial Instruments to account for its investment in AYES Canada, with changes in fair value reflected in the consolidated statements of operations.
As at December 31, 2022, the Company's maximum exposure to loss is $74,083 (2021 - $95,246), which represents the fair value of the investment.
(c)Equity-method investees
The Renewable Energy Group has non-controlling interests in operating renewable energy facilities and projects under construction with a total carrying value of $310,103 (2021 - $375,460). The Regulated Services Group has non-controlling interest of $56,199 (2021 - 37,492) in a power transmission line project under construction and other non-regulated operating entities owned by its utilities. The Liberty Development JV Inc. platform for non-regulated renewable energy, water and other sectors has a carrying value of $15,500 and (2021 - $20,898) is reported under Corporate.
Operating entities: The Company has interests in the operating entities listed below. The Company is not considered the primary beneficiary as the two partners have joint control and all key decisions must be unanimous. As such, the Company accounts for its interests using the equity method.
Economic interest Capacity
Texas Coastal Wind Facilities 51 % 861 MW
Blue Hill Wind Facility 20 % 175 MW
Red Lily Wind Facility 75 % 26.4 MW
Val-Eo Wind Facility 50 % 24 MW
During 2021, the Company acquired a 51% interest in four wind facilities located in Texas (“Texas Coastal Wind Facilities”) for $344,883. All facilities achieved commercial operations in 2021. As at December 31, 2022, the Company had issued $113,630 (2021 - $119,750) in letters of credit and guarantees of performance obligations under energy purchase agreements and decommissioning obligations on behalf of the Texas Coastal Wind Facilities. During the fourth quarter of 2022, the Company concluded that primarily as a result of continued challenges with congestion at the facilities, the carrying value of the interest in the Texas Coastal Wind Facilities was other-than-temporarily impaired. Accordingly, the Company performed a fair value analysis based on the income approach and recorded an impairment charge of $75,910 to reduce the carrying value of its equity investment in the Texas Coastal Wind Facilities from $282,726 to 206,816. Changes in assumptions of revenue forecasts, driven by expected production, basis difference and resulting spot prices, projected operating and capital expenditures would affect the estimated fair value.
Development: Pursuant to an agreement between AQN and funds managed by the Infrastructure and Power strategy of Ares Management, LLC (“Ares”), in November 2021 Ares became AQN’s new partner in its non-regulated development platform for renewable energy, water and other sectors as both parties contributed cash or assets of $19,688 to Liberty Development JV Inc. The Company is not considered the primary beneficiary as the two partners have joint control and all key decisions must be unanimous. As such, the Company accounts for its interests using the equity method.
8.Long-term investments (continued)
(c)Equity-method investees (continued)
Construction: The Renewable Energy Group has 50% equity interests in several wind and solar power electric construction projects. AQN and Ares have formed Liberty Construction (US) JV LLC (“Liberty Construction JV”) to jointly construct projects under the Renewable Energy Group. During the year, the Company contributed several projects to joint entities. The transfers resulted in a gain of $nil (2021 - $26,182). The Company holds an option to acquire the remaining interest in most construction projects at a pre-agreed price. The Company is not considered the primary beneficiary as the partners have joint control and all key decisions must be unanimous. As such, the Company accounts for its interests using the equity method.
Changes in the carrying value of equity method investees were as follows:
2022 2021
Carrying value, January 1 $ 433,850 $ 186,452
Additional Investments 110,441 418,434
Net loss attributable to AQN (21,416) (26,337)
Other comprehensive income (loss) attributable to AQN (a) (67,110) 7,733
Operating projects bought back by AQN — (129,075)
Dividend received (1,183) (2,981)
Impairment (75,910) —
Reclassification during the period (note 8(e)) — (25,634)
Other 3,130 5,258
Carrying value, December 31 $ 381,802 $ 433,850
(a) Other comprehensive loss represents the Company’s proportion of the change in fair value, recorded in OCI at the investee level, on energy derivative financial instruments designated as a cash flow hedge,

Summarized combined information for AQN's equity method investees as at December 31 is as follows:
2022 2021
Total assets $ 2,740,132 $ 2,126,934
Total liabilities 1,507,079 945,971
Net assets 1,233,053 1,180,963
AQN's ownership interest in the entities 332,663 327,555
Difference between investment carrying amount and underlying equity in net assets(a)
49,139 106,295
Total carrying value $ 381,802 $ 433,850
(a) The difference between the investment carrying amount and the underlying equity in net assets relates primarily to interest capitalized while the projects are under construction, the fair value of guarantees provided by the Company in regards to the investments, development fees and transaction costs.
8.Long-term investments (continued)
(c)Equity-method investees (continued)
Summarized combined information for AQN's equity method investees for the year ended December 31 (presented at 100%) is as follows:
2022 2021
Revenue $ 65,025 $ 20,262
Net loss $ (31,070) $ (46,293)
Other comprehensive income (loss) (a)
$ (130,729) $ 15,177
Net loss attributable to AQN $ (21,416) $ (26,337)
Other comprehensive loss attributable to AQN (a)
$ (67,110) $ 7,733

(a) Other comprehensive loss represents the Company’s proportion of the change in fair value, recorded in OCI at the investee level, on energy derivative financial instruments designated as a cash flow hedge,

Except for Liberty Global Energy Solutions B.V. (formerly Abengoa-Algonquin Global Energy Solutions B.V.) (“Liberty Global Energy Solutions”), Liberty Development JV Inc. and all construction projects are considered VIEs due to the level of equity at risk and the disproportionate voting and economic interests of the shareholders. The Company has committed loan and credit support facilities with some of its equity investees. During construction, the Company has agreed to provide cash advances and credit support for the continued development and construction of the equity investees' projects. As of December 31, 2022, the Company had issued letters of credit and guarantees of performance obligations: under a security of performance for a development opportunity; wind turbine or solar panel supply agreements; engineering, procurement, and construction agreements; interconnection agreements; energy purchase agreements; renewable energy credit agreements; and construction loan agreements. The fair value of the support provided recorded as at December 31, 2022 amounts to $8,824 (2021 - $4,612).
Summarized combined information for AQN's VIEs as at December 31 is as follows:
2022 2021
AQN's maximum exposure in regards to VIEs
Carrying amount $ 122,752 $ 86,202
Development loans receivable (d) 52,923 31,468
Performance guarantees and other commitments on behalf of VIEs 658,224 409,232
$ 833,899 $ 526,902
The commitments are presented on a gross basis assuming no recoverable value in the assets of the VIEs. The majority of the amounts committed on behalf of VIEs in the above relate to wind turbine or solar panel supply agreements as well as engineering, procurement, and construction agreements.
(d)Development loans receivable from equity investees
The Renewable Energy Group has committed loan and credit support facilities with some of its equity investees. During construction, the Company has agreed to provide cash advances and credit support (in the form of letters of credit, escrowed cash, guarantees or indemnities) in amounts necessary for the continued development and construction of the equity investees' projects. The loans generally mature on the twelfth anniversary of the development agreement or commercial operation date.
(e)San Antonio Water System and other
The Company no longer has significant influence over its 20% interest in the San Antonio Water System (“SAWS”), and therefore has discontinued the equity method of accounting in 2021. The investment is accounted for using the cost method prospectively.

Summary of Operating Entities Company accounts for its interests using the equity method.
Economic interest Capacity
Texas Coastal Wind Facilities 51 % 861 MW
Blue Hill Wind Facility 20 % 175 MW
Red Lily Wind Facility 75 % 26.4 MW
Val-Eo Wind Facility 50 % 24 MW

Equity Method Investments
Changes in the carrying value of equity method investees were as follows:
2022 2021
Carrying value, January 1 $ 433,850 $ 186,452
Additional Investments 110,441 418,434
Net loss attributable to AQN (21,416) (26,337)
Other comprehensive income (loss) attributable to AQN (a) (67,110) 7,733
Operating projects bought back by AQN — (129,075)
Dividend received (1,183) (2,981)
Impairment (75,910) —
Reclassification during the period (note 8(e)) — (25,634)
Other 3,130 5,258
Carrying value, December 31 $ 381,802 $ 433,850
(a) Other comprehensive loss represents the Company’s proportion of the change in fair value, recorded in OCI at the investee level, on energy derivative financial instruments designated as a cash flow hedge,
Summarized combined information for AQN's equity method investees for the year ended December 31 (presented at 100%) is as follows:
2022 2021
Revenue $ 65,025 $ 20,262
Net loss $ (31,070) $ (46,293)
Other comprehensive income (loss) (a)
$ (130,729) $ 15,177
Net loss attributable to AQN $ (21,416) $ (26,337)
Other comprehensive loss attributable to AQN (a)
$ (67,110) $ 7,733

(a) Other comprehensive loss represents the Company’s proportion of the change in fair value, recorded in OCI at the investee level, on energy derivative financial instruments designated as a cash flow hedge,

Schedule of Investments in Partnerships and Joint Ventures
Summarized combined information for AQN's equity method investees as at December 31 is as follows:
2022 2021
Total assets $ 2,740,132 $ 2,126,934
Total liabilities 1,507,079 945,971
Net assets 1,233,053 1,180,963
AQN's ownership interest in the entities 332,663 327,555
Difference between investment carrying amount and underlying equity in net assets(a)
49,139 106,295
Total carrying value $ 381,802 $ 433,850
(a) The difference between the investment carrying amount and the underlying equity in net assets relates primarily to interest capitalized while the projects are under construction, the fair value of guarantees provided by the Company in regards to the investments, development fees and transaction costs.

Schedule of Variable Interest Entities
Summarized combined information for AQN's VIEs as at December 31 is as follows:
2022 2021
AQN's maximum exposure in regards to VIEs
Carrying amount $ 122,752 $ 86,202
Development loans receivable (d) 52,923 31,468
Performance guarantees and other commitments on behalf of VIEs 658,224 409,232
$ 833,899 $ 526,902

v3.23.1

Long-term debt (Tables)
12 Months Ended

Dec. 31, 2022

Debt Disclosure [Abstract]

Schedule of Long Term Debt
Long-term debt consists of the following:
Borrowing type Weighted average coupon Maturity Par value December 31, 2022 December 31, 2021
Senior unsecured revolving credit facilities (a) — 2024-2027 N/A $ 351,786 $ 368,806
Senior unsecured bank credit facilities and delayed draw term facility (b) — 2023-2031 N/A 773,643 141,956
Commercial paper — 2023 N/A 407,000 338,700
U.S. dollar borrowings
Senior unsecured notes (Green Equity Units) (c) 1.18 % 2026 $ 1,150,000 1,142,814 1,140,801
Senior unsecured notes (d) 3.39 % 2023-2047 $ 1,505,000 1,496,101 1,689,792
Senior unsecured utility notes 6.34 % 2023-2035 $ 142,000 154,271 155,571
Senior secured utility bonds 4.71 % 2026-2044 $ 556,209 554,822 558,177
Canadian dollar borrowings
Senior unsecured notes (e) 3.68 % 2027-2050 C$ 1,200,000 882,899 1,099,403
Senior secured project notes 10.21 % 2027 C$ 20,349 15,024 18,344
Chilean Unidad de Fomento borrowings
Senior unsecured utility bonds 4.05 % 2028-2040 CLF 1,637 77,206 77,963
$ 5,855,566 $ 5,589,513
Subordinated U.S. dollar borrowings
Subordinated unsecured notes (f) 5.25 % 2082 C$ 400,000 291,238 —
Subordinated unsecured notes (f) 5.56 % 2078-2082 $ 1,387,500 1,365,213 621,862
$ 7,512,017 $ 6,211,375
Less: current portion (423,274) (356,397)
$ 7,088,743 $ 5,854,978
Short-term obligations of $705,386 that are expected to be refinanced using the long-term credit facilities are presented as long-term debt.
Long-term debt issued at a subsidiary level (project notes or utility bonds) relating to a specific operating facility is generally collateralized by the respective facility with no other recourse to the Company. Long-term debt issued at a subsidiary level whether or not collateralized generally has certain financial covenants, which must be maintained on a quarterly basis. Non-compliance with the covenants could restrict cash distributions/dividends to the Company from the specific facilities.
9.Long-term debt (continued)
The following table sets out the bank credit facilities available to AQN and its operating groups as at December 31, 2022:
December 31, 2022 December 31, 2021
Revolving and term credit facilities $ 4,513,300 $ 3,217,000
Funds drawn on facilities/ commercial paper issued (1,532,500) (849,600)
Letters of credit issued (465,200) (317,200)
Liquidity available under the facilities 2,515,600 2,050,200
Undrawn portion of uncommitted letter of credit facilities (226,900) (224,000)
Cash on hand 57,623 125,157
Total liquidity and capital reserves $ 2,346,323 $ 1,951,357
Recent financing activities:
(a)Senior unsecured revolving credit facilities
Regulated Services Group
On April 29, 2022, the Regulated Services Group entered into two new senior unsecured revolving credit facilities: a $1,000,000 senior unsecured revolving credit facility with an initial maturity date of April 29, 2027 (the “Long-Term Regulated Services Credit Facility”) and a $500,000 short-term senior unsecured revolving credit facility maturing originally on March 31, 2023 and extended to February 28, 2024, subsequent to year-end. Subject to the terms and conditions therein, the Long-Term Regulated Services Credit Facility may be extended for two additional one-year periods. In conjunction with the new facilities, the Regulated Services Group’s $500,000 senior unsecured syndicated revolving credit facility was cancelled.
On December 23, 2022, the Regulated Services Group amended and restated its $75,000 senior unsecured revolving credit facility in Bermuda with a new maturity date of December 31, 2024. On June 24, 2022, the Regulated Services Group entered into a new $25,000 senior unsecured bilateral revolving credit facility in Bermuda that matures on June 24, 2024.
Renewable Energy Group
On July 22, 2022, the Renewable Energy Group amended and restated its $500,000 senior unsecured syndicated revolving credit facility (the "Renewable Energy Credit Facility") with a new maturity date of July 22, 2027. Subject to the terms and conditions therein, the Renewable Energy Credit Facility may be extended for additional one-year periods.
On July 22, 2022, the Renewable Energy Group entered into a new $250,000 uncommitted bilateral letter of credit facility. On November 8, 2022, the Renewable Energy Group's $350,000 uncommitted letter of credit facility was amended and restated with a new maturity date of June 30, 2024.
(b)Senior unsecured bank credit facilities
On November 30, 2022, the Regulated Services Group amended and restated its $1,100,000 senior unsecured delayed draw term facility ("the "Regulated Services Delayed Draw Term Facility") with the new maturity date of November 29, 2023.
(c)U.S dollar senior unsecured notes (Green Equity Units)
In June 2021, the Company sold 23,000,000 equity units (the “Green Equity Units”) for total gross proceeds of $1,150,000. Each Green Equity Unit was issued in a stated amount of $50, at issuance, consisted of a contract to purchase AQN common shares (the “share purchase contract”) and a 5% undivided beneficial ownership interest in a remarketable senior note of AQN due June 15, 2026, issued in the principal amount of $1,000.
9.Long-term debt (continued)
Recent financing activities (continued):
(c)U.S dollar senior unsecured notes (Green Equity Units) (continued)
Total annual distributions on the Green Equity Units are at a rate of 7.75%, consisting of interest on the notes (1.18% per year) and payments under the share purchase contract (6.57% per year). The interest rate on the notes will be reset following a successful marketing, which would occur in 2024. The present value of the contract adjustment payments was estimated at $222,378 and is recorded against additional paid-in capital (“APIC”) to the extent of the APIC balance and against retained earnings (deficit) for the remainder. The corresponding amount of $222,378 was recorded in other liabilities and is accreted over the three-year period (note 12(a)).
Each share purchase contract requires the holder to purchase by no later than June 15, 2024 for a price of $50 in cash, a number of AQN common shares (“common shares”) based on the applicable market value to be determined using the volume-weighted average price of the common shares over a 20-day trading period ending June 14, 2024. The minimum settlement rate under the purchase contracts is 2.7778 common shares, which is approximately equal to the $50 stated amount per Green Equity Unit, divided by the threshold appreciation price of $18 per common share. The maximum settlement rate under the purchase contracts is 3.3333 common shares, which is approximately equal to the $50 stated amount per Green Equity Unit, divided by $15 per common share.
The common share purchase obligation of holders of Green Equity Units will be satisfied by the proceeds raised from a successful remarketing of the notes, unless a holder has elected to settle with separate cash. Holders’ beneficial ownership interest in each note has been pledged to AQN to secure the holders' obligation to purchase common shares under the related share purchase contract.
Prior to the issuance of common shares, the share purchase contracts, if dilutive, will be reflected in the Company's diluted earnings per share calculations using the treasury stock method.
(d)U.S. dollar senior unsecured notes
On April 30, 2022, the Company repaid a $80,000 senior unsecured note on its maturity.
On August 1, 2022, the Company repaid a $115,000 senior unsecured note on its maturity.
Subsequent to year end, the Company repaid a $15,000 senior unsecured note on its maturity.
(e)Canadian dollar senior unsecured notes
On February 15, 2022, the Company repaid a C$200,000 senior unsecured note on its maturity. On February 15, 2021, the Renewable Energy Group repaid a C$150,000 unsecured note upon its maturity. Concurrent with the repayments, the Renewable Energy Group unwound and settled the related cross-currency fixed-for-fixed interest rate swap (note 24(b)(iii)).
On April 9, 2021, the Renewable Energy Group issued C$400,000 senior unsecured debentures bearing interest at 2.85% with a maturity date of July 15, 2031. The notes were sold at a price of C$999.92 per C$1,000.00 principal amount. Concurrent with the offering, the Renewable Energy Group entered into a fixed-for-fixed cross-currency interest rate swap to convert the Canadian-dollar-denominated coupon and principal payments from the offering into U.S. dollars (note 24(b)(iii)).
9.Long-term debt (continued)
Recent financing activities (continued):
(f)Subordinated unsecured notes
On January 18, 2022, the Company closed (i) an underwritten public offering in the United States (the “U.S. Offering”) of $750,000 aggregate principal amount of 4.75% fixed-to-fixed reset rate junior subordinated notes series 2022-B due January 18, 2082 (the “U.S. Notes”); and (ii) an underwritten public offering in Canada (the “Canadian Offering” and, together with the U.S. Offering, the “Offerings”) of C$400,000 (approximately $320,000) aggregate principal amount of 5.25% fixed-to-fixed reset rate junior subordinated notes series 2022-A due January 18, 2082 (the “Canadian Notes” and, together with the U.S. Notes, the “Notes”). Concurrent with the pricing of the Offerings, the Company entered into a cross currency interest rate swap to convert the Canadian dollar denominated proceeds from the Canadian Offering into U.S. dollars, and a forward starting swap to fix the interest rate for the second five year term of the U.S. Notes, resulting in an anticipated effective interest rate to the Company of approximately 4.95% throughout the first ten-year period of the Notes.

As of December 31, 2022, the Company had accrued $70,274 in interest expense (2021 - $49,806). Interest expense for the years ended December 31 consists of the following:
2022 2021
Long-term debt $ 261,535 $ 217,123
Commercial paper, credit facility draws and related fees 43,015 17,065
Accretion of fair value adjustments (16,547) (18,174)
Capitalized interest and AFUDC capitalized on regulated property (10,802) (6,521)
Other 1,373 61
$ 278,574 $ 209,554

Principal payments due in the next five years and thereafter are as follows:
2023 2024 2025 2026 2027 Thereafter Total
$ 1,128,660 $ 359,371 $ 45,262 $ 1,265,711 $ 719,144 $ 4,019,166 $ 7,537,314

Schedule of Maturities of Long-term Debt
Principal payments due in the next five years and thereafter are as follows:
2023 2024 2025 2026 2027 Thereafter Total
$ 1,128,660 $ 359,371 $ 45,262 $ 1,265,711 $ 719,144 $ 4,019,166 $ 7,537,314

Schedule of Interest Expense Interest expense for the years ended December 31 consists of the following:
2022 2021
Long-term debt $ 261,535 $ 217,123
Commercial paper, credit facility draws and related fees 43,015 17,065
Accretion of fair value adjustments (16,547) (18,174)
Capitalized interest and AFUDC capitalized on regulated property (10,802) (6,521)
Other 1,373 61
$ 278,574 $ 209,554

v3.23.1

Pension and other post-retirement benefits (Tables)
12 Months Ended

Dec. 31, 2022

Retirement Benefits [Abstract]

Schedule of Benefit Obligations Fair Value of Plan Assets and Funded Status The following table sets forth the projected benefit obligations, fair value of plan assets, and funded status of the Company’s plans as of December 31:
Pension benefits OPEB
2022 2021 2022 2021
Change in projected benefit obligation
Projected benefit obligation, beginning of year $ 765,618 $ 834,913 $ 292,646 $ 306,524
Projected benefit obligation assumed from business combination 87,933 — 5,195 —
Plan Settlements (112) (1,294) — —
Service cost 16,309 14,673 6,277 7,307
Interest cost 24,787 20,676 9,146 8,048
Actuarial gain (198,074) (36,597) (82,991) (18,977)
Contributions from retirees — — 2,220 2,040
Plan amendments — 237 (2,452) 310
Medicare Part D — — 367 373
Benefits paid (68,197) (66,800) (13,078) (12,979)
Foreign exchange (129) (190) — —
Projected benefit obligation, end of year $ 628,135 $ 765,618 $ 217,330 $ 292,646
Change in plan assets
Fair value of plan assets, beginning of year 648,864 629,157 192,375 176,616
Plan assets acquired in business combination 74,532 — 8,577 —
Actual return on plan assets (109,118) 58,721 (30,105) 15,200
Employer contributions 23,296 29,058 11,811 11,178
Plan Settlements (112) (1,294) — —
Contributions from retirees — — 2,220 1,988
Medicare Part D subsidy receipts — — 367 372
Benefits paid (68,197) (66,800) (13,078) (12,979)
Foreign exchange (10) 22 — —
Fair value of plan assets, end of year $ 569,255 $ 648,864 $ 172,167 $ 192,375
Unfunded status $ (58,880) $ (116,754) $ (45,163) $ (100,271)
Amounts recognized in the consolidated balance sheets consist of:
Non-current assets (note 11) 12,264 11,751 14,218 11,879
Current liabilities (1,907) (1,902) (3,039) (699)
Non-current liabilities (69,237) (126,603) (56,342) (111,451)
Net amount recognized
$ (58,880) $ (116,754) $ (45,163) $ (100,271)
Information for pension and OPEB plans with an accumulated benefit obligation in excess of plan assets:
Pension OPEB
2022 2021 2022 2021
Accumulated benefit obligation $ 413,041 $ 489,043 $ 198,463 $ 274,649
Fair value of plan assets $ 364,229 $ 396,679 $ 139,368 $ 162,592

Information for pension and OPEB plans with a projected benefit obligation in excess of plan assets:
Pension OPEB
2022 2021 2022 2021
Projected benefit obligation $ 489,140 $ 580,841 $ 198,463 $ 274,649
Fair value of plan assets $ 417,994 $ 452,333 $ 139,368 $ 162,592

Schedule of Amounts Recognized in Other Comprehensive Loss Pension and post-employment actuarial changes
Change in AOCI, before tax Pension OPEB
Actuarial losses (gains) Past service gains Actuarial losses (gains) Past service losses (gains)
Balance, January 1, 2021 $ 57,231 $ (5,306) $ (4,299) $ —
Additions to AOCI (59,754) 237 (24,126) (24)
Amortization in current period (13,130) 1,626 (2,021) 334
Amortization due to plan settlements (210) — — —
Reclassification to regulatory accounts 31,670 (752) 14,816 —
Balance, December 31, 2021 $ 15,807 $ (4,195) $ (15,630) $ 310
Additions to AOCI (47,473) — (41,527) (24)
Amortization in current period (3,429) 1,584 56 (2,476)
Amortization due to plan settlements 15 — — —
Reclassification to regulatory accounts 34,409 (752) 23,551 —
Balance, December 31, 2022 $ (671) $ (3,363) $ (33,550) $ (2,190)

Schedule of Weighted Average Assumptions Used to Determine Net Benefit Obligation
Weighted average assumptions used to determine net benefit obligation for 2022 and 2021 were as follows:
Pension benefits OPEB
2022 2021 2022 2021
Discount rate 5.48 % 2.94 % 5.49 % 3.00 %
Interest crediting rate (for cash balance plans) 4.50 % 4.00 % N/A N/A
Rate of compensation increase 3.70 % 4.00 % N/A N/A
Health care cost trend rate
Before age 65 6.00 % 5.88 %
Age 65 and after 6.00 % 5.88 %
Assumed ultimate medical inflation rate 4.75 % 4.75 %
Year in which ultimate rate is reached 2033 2031

Schedule of Weighted Average Assumptions Used to Determine Net Benefit Cost
Weighted average assumptions used to determine net benefit cost for 2022 and 2021 were as follows:
Pension benefits OPEB
2022 2021 2022 2021
Discount rate 2.94 % 2.49 % 3.00 % 2.58 %
Expected return on assets 6.19 % 6.20 % 6.48 % 4.79 %
Rate of compensation increase 3.91 % 3.99 % n/a n/a
Health care cost trend rate
Before Age 65 5.88 % 5.12 %
Age 65 and after 5.88 % 5.12 %
Assumed ultimate medical inflation rate 4.75 % 4.05 %
Year in which ultimate rate is reached 2031 2031

Components of Net Benefit Costs For Pension Plans and OPEB Recorded as Part of Administrative Expenses
The following table lists the components of net benefit cost for the pension and OPEB plans. Service cost is recorded as part of operating expenses and non-service costs are recorded as part of other net losses in the consolidated statements of operations. The employee benefit costs related to businesses acquired are recorded in the consolidated statements of operations from the date of acquisition.
Pension benefits OPEB
2022 2021 2022 2021
Service cost $ 16,309 $ 14,673 $ 6,277 $ 7,307
Non-service costs
Interest cost 24,787 20,676 9,146 8,048
Expected return on plan assets (41,226) (35,972) (11,359) (10,052)
Amortization of net actuarial loss 3,452 13,126 (56) 2,021
Amortization of prior service credits (1,584) (1,626) 24 11
Amortization due to plan settlements (15) 198 — —
Amortization of regulatory accounts 22,951 19,665 4,829 218
$ 8,365 $ 16,067 $ 2,584 $ 246
Net benefit cost $ 24,674 $ 30,740 $ 8,861 $ 7,553

Schedule of Target Asset Allocation
The Company’s target asset allocation is as follows:
Asset class Target (%) Range (%)
Equity securities 41 %
30% -100%
Debt securities 49 %
20% - 60%
Other 10 %
0% - 20%
100 %

The fair values of investments as of December 31, 2022, by asset category, are as follows:
Asset class 2022 Percentage
Equity securities $ 317,088 43 %
Debt securities 356,654 48 %
Other 67,680 9 %
$ 741,422 100 %

Schedule of Changes in Fair Value of Plan Assets
The following table summarizes the changes fair value of these level 3 assets as of December 31:
Level 3
Balance, January 1, 2022 $ 17,314
Contributions into funds 4,781
Return on assets 2,094
Distributions (2,285)
Balance, December 31, 2022 $ 21,904

Schedule of Expected Benefit Payments
The expected benefit payments over the next ten years are as follows:
2023 2024 2025 2026 2027 2028-2032
Pension plan $ 48,174 $ 47,428 $ 49,794 $ 50,585 $ 50,433 $ 259,082
OPEB $ 11,483 $ 12,025 $ 12,548 $ 12,925 $ 13,479 $ 72,684

v3.23.1

Other assets (Tables)
12 Months Ended

Dec. 31, 2022

Deferred Costs, Capitalized, Prepaid, and Other Assets Disclosure [Abstract]

Schedule of Other Assets
Other assets consist of the following:
2022 2021
Restricted cash $ 43,562 $ 36,232
Pension and OPEB plan assets (note 10(a)) 26,482 23,630
Long-term deposits and cash collateral 22,537 14,713
Income taxes recoverable 7,100 7,649
Deferred financing costs (a) 28,586 30,544
Other (b) 21,596 10,913
$ 149,863 $ 123,681
Less: current portion (22,564) (16,153)
$ 127,299 $ 107,528
(a)Deferred financing costs
Deferred financing costs represent costs of arranging the Company’s revolving credit facilities and intercompany loans as well as the portion of transactions costs related to the Green Equity Units (note 9(c)) that will be recorded against the common shares when issued.

(b)Other
Other includes various deferred charges that are expected to be transferred to utility plant upon reaching certain milestones as well as prepaid long-term service contracts.

v3.23.1

Other long-term liabilities (Tables)
12 Months Ended

Dec. 31, 2022

Other Liabilities Disclosure [Abstract]

Schedule Of Other Long Term Liabilities
Other long-term liabilities consist of the following:
2022 2021
Contract adjustment payments (a) $ 113,876 $ 187,580
Asset retirement obligations (b) 116,584 142,147
Advances in aid of construction (c) 88,546 82,584
Environmental remediation obligation (d) 42,457 55,224
Customer deposits (e) 34,675 32,629
Unamortized investment tax credits (f) 17,649 17,439
Deferred credits and contingent consideration (g) 39,498 43,495
Preferred shares, Series C (h) 12,072 13,348
Hook up fees (i) 32,463 21,904
Lease liabilities (note 1(q)) 21,834 22,512
Contingent development support obligations (j) 8,824 4,615
Note payable to related party (k) 25,808 25,808
Other 41,156 34,534
$ 595,442 $ 683,819
Less: current portion (134,212) (167,908)
$ 461,230 $ 515,911
(a)Contract adjustment payment
In June 2021, the Company sold 23,000,000 Green Equity Units for total gross proceeds of $1,150,000 (note 9(c)). Total annual distributions on the Green Equity Units are at a rate of 7.75%, consisting of interest on the notes (1.18% per year) and payments under the share purchase contract (6.57% per year). The present value of the contract adjustment payments was estimated at $222,378 and recorded in other liabilities. The contract adjustment payments amount is accreted over the three-year period.
(b)Asset retirement obligations
    Asset retirement obligations mainly relate to legal requirements to: (i) remove wind farm facilities upon termination of land leases; (ii) cut (disconnect from the distribution system), purge (cleanup of natural gas and polychlorinated biphenyls (“PCB”) contaminants) and cap natural gas mains within the natural gas distribution and transmission system when mains are retired in place, or sections of natural gas main are removed from the pipeline system; (iii) clean and remove storage tanks containing waste oil and other waste contaminants; (iv) remove certain river water intake structures and equipment; (v) dispose of coal combustion residuals and PCB contaminants; (vi) remove asbestos upon major renovation or demolition of structures and facilities; and (vii) decommission and restore power generation engines and related facilities.
Changes in the asset retirement obligations are as follows:
2022 2021
Opening balance $ 142,147 $ 79,968
Obligation assumed 793 57,067
  Retirement activities (27,980) (4,133)
  Accretion 4,589 4,381
  Change in cash flow estimates (2,965) 4,864
Closing balance $ 116,584 $ 142,147
12.Other long-term liabilities (continued)
(b)Asset retirement obligations (continued)
As the cost of retirement of utility assets in the United States is expected to be recovered through rates, a corresponding regulatory asset is recorded for liability accretion and asset depreciation expense (note 7(j)).
(c)Advances in aid of construction
The Company’s regulated utilities have various agreements with real estate development companies (the “developers”) conducting business within the Company’s utility service territories, whereby funds are advanced to the Company by the developers to assist with funding some or all of the costs of the development.
In many instances, developer advances can be subject to refund, but the refund is non-interest bearing. Refunds of developer advances are made over periods generally ranging from 5 to 40 years. Advances not refunded within the prescribed period are usually not required to be repaid. After the prescribed period has lapsed, any remaining unpaid balance is transferred to contributions in aid of construction and recorded as an offsetting amount to the cost of property, plant and equipment. In 2022, $1,299 (2021 - $6,376) was transferred from advances in aid of construction to contributions in aid of construction.
(d)Environmental remediation obligation
A number of the Company's regulated utilities were named as potentially responsible parties for remediation of several sites at which hazardous waste is alleged to have been disposed as a result of historical operations of manufactured natural gas plants (“MGP”) and related facilities. The Company is currently investigating and remediating, as necessary, those MGP and related sites in accordance with plans submitted to the agency with authority for each of the respective sites.
The Company estimates the remaining undiscounted, unescalated cost of the environmental cleanup activities will be $48,346 (2021 - $57,167), which at discount rates ranging from 3.4% to 4.2% represents the recorded accrual of $42,457 as of December 31, 2022 (2021 - $55,224 ). Approximately $27,410 is expected to be incurred over the next three years, with the balance of cash flows to be incurred over the following 30 years.
Changes in the environmental remediation obligation are as follows:
2022 2021
Opening balance $ 55,224 $ 69,383
  Remediation activities (5,243) (9,865)
  Accretion 2,167 1,025
  Changes in cash flow estimates 1,344 2,265
  Revision in assumptions (11,035) (7,584)
Closing balance $ 42,457 $ 55,224
The Regulators for the New England Gas System and Energy North Gas System provide for the recovery of actual expenditures for site investigation and remediation over a period of 7 years and, accordingly, as of December 31, 2022, the Company has reflected a regulatory asset of $70,529 (2021 - $81,802) for the MGP and related sites (note 7(g)).
(e)Customer deposits
Customer deposits result from the Company’s obligation by Regulators to collect a deposit from customers of its facilities under certain circumstances when services are connected. The deposits are refundable as allowed under the facilities’ regulatory agreement.
12.Other long-term liabilities (continued)
(f)Unamortized investment tax credits
The unamortized investment tax credits were assumed in connection with the acquisition of the Empire Electric System. The investment tax credits are associated with an investment made in a generating station. The credits are being amortized over the life of the generating station.
(g)Deferred credits and contingent consideration
Deferred credits and contingent consideration include unresolved contingent consideration related to prior acquisitions which is expected to be paid. In 2021, the Company recorded contingent consideration related to the acquisition of AAGES Sugar Creek Wind, LLC in an amount of $18,641 (note 3(f)).
(h)Preferred shares, Series C
AQN has 100 redeemable preferred shares, Series C issued and outstanding. The preferred shares are mandatorily redeemable in 2031 for C$53,400 per share and have a contractual cumulative cash dividend paid quarterly until the date of redemption based on a prescribed payment schedule indexed in proportion to the increase in CPI over the term of the shares. The preferred shares, Series C are convertible into common shares at the option of the holder and the Company, at any time after May 20, 2031 and before June 19, 2031, at a conversion price of C$53,400 per share.
As these shares are mandatorily redeemable for cash, they are classified as liabilities in the consolidated financial statements. The preferred shares, Series C are accounted for under the effective interest method, resulting in accretion of interest expense over the term of the shares. Dividend payments are recorded as a reduction of the preferred shares, Series C carrying value.
Estimated dividend payments due in the next five years and dividend and redemption payments thereafter are as follows:
2023 $ 1,245
2024 1,443
2025 1,459
2026 1,316
2027 1,262
Thereafter to 2031 4,654
Redemption amount 3,943
$ 15,322
Less: amounts representing interest (3,250)
$ 12,072
Less current portion (1,245)
$ 10,827
(i)Hook up fees
Hook up fees result from the collection from customers of funds for installation and connection to the utility's infrastructure. The fees are refundable as allowed under the facilities’ regulatory agreement.
(j)Contingent development support obligations
The Company provides credit support necessary for the continued development and construction of its equity investees' wind and solar power electric development projects and infrastructure development projects. The contingent development support obligations represent the fair value of the support provided (note 8(c)).
12.Other long-term liabilities (continued)
(k)Note payable to related party
In 2020, a subsidiary of the Company made a tax equity investment into Altavista Solar Subco, LLC, an equity investee of the Company and indirect owner of the Altavista Solar Project. Following the closing of the construction financing facility for the Altavista Solar Project, certain excess funds were distributed to the Company and in return the Company issued a promissory note payable of $30,493 to Altavista Solar Subco, LLC. The promissory note bears an interest rate of 0.675%, compounded annually. The note was repaid in full during the second quarter of 2021.
In 2021, a subsidiary of the Company made a tax equity investment into New Market Solar Investco, LLC, an equity investee of the Company and indirect owner of the New Market Solar Project (note 8(c)). Following the closing of the construction financing facility for the New Market Solar Project, certain excess funds were distributed to the Company and in return the Company issued a promissory note of $25,808 payable to New Market Solar Investco, LLC. The promissory note bears an interest rate of 4% annually and has a maturity date of December 16, 2031.

v3.23.1

Shareholders' capital (Tables)
12 Months Ended

Dec. 31, 2022

Equity [Abstract]

Schedule of Number of Common Shares
Number of common shares
2022 2021
Common shares, beginning of year 671,960,276 597,142,219
Public offering 2,861,709 67,611,465
Dividend reinvestment plan 7,676,666 6,184,686
Exercise of share-based awards (c) 1,115,398 1,020,020
Conversion of convertible debentures 754 1,886
Common shares, end of year 683,614,803 671,960,276

Schedule of Shares Issued and Outstanding
The Company has the following preferred shares, Series A and preferred shares, Series D issued and outstanding as at December 31, 2022 and 2021:
Preferred shares Number of shares Price per share Carrying amount C$ Carrying amount $
Series A 4,800,000 C$ 25 C$ 116,546 $ 100,463
Series D 4,000,000 C$ 25 C$ 97,259 $ 83,836
$ 184,299

Schedule of Share-based Compensation Expense
For the year ended December 31, 2022, AQN recorded $10,920 (2021 - $8,395) in total share-based compensation expense as follows:
2022 2021
Share options $ 980 $ 939
Director deferred share units 960 821
Employee share purchase 562 592
Performance and restricted share units 8,418 6,043
Total share-based compensation $ 10,920 $ 8,395

Schedule of Fair Value of Share Options Granted
The following assumptions were used in determining the fair value of share options granted:
2022 2021
Risk-free interest rate 1.9 % 1.1 %
Expected volatility 23 % 23 %
Expected dividend yield 4.3 % 4.1 %
Expected life 5.50 years 5.50 years
Weighted average grant date fair value per option C$ 2.44 C$ 2.46

Schedule of Stock Option Activity
Share option activity during the years is as follows:
Number of
awards Weighted
average
exercise
price Weighted
average
remaining
contractual
term (years) Aggregate
intrinsic
value
Balance, January 1, 2021 2,110,448 C$ 15.45 6.55 C$ 11,604
Granted 437,006 19.64 7.22 —
Exercised (506,926) 13.92 5.95 1,453
Forfeited — — — —
Balance, December 31, 2021 2,040,528 C$ 15.45 6.11 C$ 3,145
Granted 646,090 19.11 7.22 —
Exercised (40,074) 13.92 5.95 103
Forfeited (19,764) 19.11 — —
Balance, December 31, 2022 2,626,780 C$ 16.02 5.63 C$ —
Exercisable, December 31, 2022 2,052,946 C$ 17.35 5.63 C$ —

Schedule of Performance Stock Units
A summary of the PSUs and RSUs follows:
Number of awards Weighted
average
grant-date
fair value Weighted
average
remaining
contractual
term (years) Aggregate
intrinsic
value
Balance, January 1, 2021 2,721,207 C$ 16.58 0.93 C$ 54,560
Granted, including dividends 805,433 19.94 2.77 12,881
Exercised (865,067) 13.79 — 17,005
Forfeited (217,901) 18.64 — 3,981
Balance, December 31, 2021 2,443,672 C$ 18.07 1.72 C$ 44,646
Granted, including dividends 1,090,457 17.99 2.00 17,524
Exercised (1,221,620) 12.62 — 23,636
Forfeited (202,799) 18.94 — 418
Balance, December 31, 2022 2,109,710 C$ 18.38 1.76 C$ 18,608
Exercisable, December 31, 2022 769,458 C$ 18.70 0.10 C$ 6,787

v3.23.1

Accumulated other comprehensive income (loss) (Tables)
12 Months Ended

Dec. 31, 2022

Accumulated Other Comprehensive Income (Loss), Net of Tax [Abstract]

Schedule of Accumulated Other Comprehensive Income (Loss) AOCI consists of the following balances, net of tax:
Foreign currency cumulative translation Unrealized gain on cash flow hedges Pension and post-employment actuarial changes Total
Balance, January 1, 2021 $ (39,725) $ 50,817 $ (33,599) $ (22,507)
Other comprehensive income (loss) (25,982) (97,103) 32,247 (90,838)
Amounts reclassified from AOCI to the consolidated statement of operations (4,288) 42,772 9,804 48,288
Net current period OCI $ (30,270) $ (54,331) $ 42,051 $ (42,550)
OCI attributable to the non-controlling interests (249) — — (249)
Net current period OCI attributable to shareholders of AQN $ (30,519) $ (54,331) $ 42,051 $ (42,799)
Amount reclassified from AOCI to non-controlling interest (6,371) — — (6,371)
Balance, December 31, 2021 $ (76,615) $ (3,514) $ 8,452 $ (71,677)
Other comprehensive income (loss) (18,013) (128,838) 23,722 (123,129)
Amounts reclassified from AOCI to the consolidated statement of operations (5,489) 34,543 4,039 33,093
Net current period OCI $ (23,502) (94,295) 27,761 $ (90,036)
OCI attributable to the non-controlling interests 1,650 — — 1,650
Net current period OCI attributable to shareholders of AQN $ (21,852) (94,295) 27,761 $ (88,386)
Balance, December 31, 2022 $ (98,467) $ (97,809) $ 36,213 $ (160,063)

v3.23.1

Dividends (Tables)
12 Months Ended

Dec. 31, 2022

Disclosure Cash Dividends [Abstract]

Schedule of Dividends Dividends declared were as follows:
2022 2021
Dividend Dividend per share Dividend Dividend per share
Common shares $ 486,043 $ 0.7130 $ 423,023 $ 0.6669
Preferred shares, Series A C$ 6,194 C$ 1.2905 C$ 6,194 C$ 1.2905
Preferred shares, Series D C$ 5,091 C$ 1.2728 C$ 5,091 C$ 1.2728

v3.23.1

Non-controlling interests and redeemable non-controlling interests (Tables)
12 Months Ended

Dec. 31, 2022

Noncontrolling Interest [Abstract]

Schedule of Net Loss Attributable to Non-controlling Interests
Net effect attributable to non-controlling interests for the years ended December 31 consists of the following:
2022 2021
HLBV and other adjustments attributable to:
Non-controlling interests - tax equity partnership units $ 108,695 $ 88,417
Non-controlling interests - redeemable tax equity partnership units 6,298 6,902
Other net earnings attributable to:
Non-controlling interests (3,670) (5,682)
$ 111,323 $ 89,637
Redeemable non-controlling interest, held by related party (15,157) (10,435)
Net effect of non-controlling interests
$ 96,166 $ 79,202
Non-controlling interests - tax equity partnership units (a) Other non-controlling interests (b) Non-controlling interests held by related parties (c)
2022 2021 2022 2021 2022 2021
Opening balance $ 1,377,117 $ 388,253 $ 64,807 $ 11,234 $ 81,158 $ 59,125
Net earnings attributable to NCI (105,371) (87,422) 345 3,354 — —
Contributions received, net 6,182 1,058,929 267,515 51,451 — 39,376
Dividends and distributions declared (40,086) (11,795) — (1,021) (20,978) (17,793)
Repurchase of non-controlling interest (12,249) — — — — —
Non-controlling interest assumed on asset acquisition — 29,141 — — — —
OCI 15 11 695 (211) (2,358) 450
Closing balance $ 1,225,608 $ 1,377,117 $ 333,362 $ 64,807 $ 57,822 $ 81,158
Changes in redeemable non-controlling interests are as follows:
Redeemable non-controlling interests held by related party Redeemable non-controlling interests
2022 2021 2022 2021
Opening balance $ 306,537 $ 306,316 $ 12,989 $ 20,859
Net earnings attributable to NCI 15,157 10,435 (6,298) (6,902)
Contributions, net of costs — — 5,000 —
Dividends and distributions declared (13,838) (10,214) (171) (968)
Closing balance $ 307,856 $ 306,537 $ 11,520 $ 12,989

v3.23.1

Income taxes (Tables)
12 Months Ended

Dec. 31, 2022

Income Tax Disclosure [Abstract]

Schedule of Provision for Income Taxes The differences are as follows:
2022 2021
Expected income tax expense at Canadian statutory rate $ (97,962) $ 37,691
Increase (decrease) resulting from:
Effect of differences in tax rates on transactions in and within foreign jurisdictions and change in tax rates (55,315) (47,600)
Adjustments from investments carried at fair value 51,314 2,709
Non-controlling interests share of income 30,025 25,135
Change in valuation allowance 41,702 (118)
Non-deductible acquisition costs 1,341 3,733
Acquisition related state deferred tax adjustments 5,998 —
Capital gain rate differential on disposal of renewable assets (7,340) —
Tax credits (18,440) (49,415)
Adjustment relating to prior periods (1,390) 1,333
Deferred income taxes on regulated income recorded as regulatory assets (2,155) (3,807)
Amortization and settlement of excess deferred income tax (14,855) (16,778)
Other 5,564 3,692
Income tax recovery $ (61,513) $ (43,425)

Schedule of Income (Loss) Before Taxes
For the years ended December 31, 2022 and 2021, earnings (loss) before income taxes consist of the following:
2022 2021
Canada (1)
$ (363,050) $ (60,848)
U.S. (37,322) 153,719
Other regions 30,704 49,361
$ (369,668) $ 142,232
(1) Inclusive of fair value gain (loss) on investments carried at fair value (note 8)

Schedule of Income Tax Expenses (Recovery) Attributable to Income (Loss)
Income tax expense (recovery) attributable to income (loss) consists of:
Current Deferred Total
Year ended December 31, 2022
Canada $ 4,184 $ (74,595) $ (70,411)
United States 1,579 6,183 7,762
Other regions 2,080 (944) 1,136
$ 7,843 $ (69,356) $ (61,513)
Year ended December 31, 2021
Canada $ 4,560 $ (33,993) $ (29,433)
United States 1,024 (19,772) (18,748)
Other regions 1,653 3,103 4,756
$ 7,237 $ (50,662) $ (43,425)

Schedule of Tax Effect of Temporary Difference Between Assets and Liability
The tax effect of temporary differences between the financial statement carrying amounts of assets and liabilities and their respective tax bases that give rise to significant portions of the deferred tax assets and deferred tax liabilities as of December 31, 2022 and 2021 are presented below:
2022 2021
Deferred tax assets:
Non-capital loss, investment tax credits, currently non-deductible interest expenses, and financing costs $ 878,000 $ 761,666
Pension and OPEB 16,845 46,580
Environmental obligation 12,118 15,271
Regulatory liabilities 156,285 166,939
Other 61,917 64,460
Total deferred income tax assets $ 1,125,165 $ 1,054,916
Less: valuation allowance (107,583) (27,471)
Total deferred tax assets $ 1,017,582 $ 1,027,445
Deferred tax liabilities:
Property, plant and equipment $ 846,331 $ 782,829
Outside basis differentials 315,581 412,665
Regulatory accounts 303,059 300,072
Other 33,834 30,471
Total deferred tax liabilities $ 1,498,805 $ 1,526,037
Net deferred tax liabilities $ (481,223) $ (498,592)
Consolidated balance sheets classification:
Deferred tax assets $ 84,416 $ 31,595
Deferred tax liabilities (565,639) (530,187)
Net deferred tax liabilities $ (481,223) $ (498,592)

Summary of Valuation Allowance
The following table illustrates the annual movement in the deferred tax valuation allowance:
2022 2021
Beginning balance $ 27,471 $ 29,824
Charged to income tax expense (recovery) 41,702 (118)
Charged (reduction) to OCI 40,613 (1,707)
Reductions to other accounts (2,203) (528)
Ending balance $ 107,583 $ 27,471

Schedule of Non Capital Losses Carry Forwards
As of December 31, 2022, the Company had non-capital losses carried forward and tax credits available to reduce future years' taxable income, which expire as follows:
Non-capital loss carryforward and credits 2023—2027 2028+ Total
Canada $ 3,261 $ 728,529 $ 731,790
US 9,962 1,707,139 1,717,101
Total non-capital loss carryforward $ 13,223 $ 2,435,668 $ 2,448,891
Tax credits $ 4,428 $ 151,676 $ 156,104

v3.23.1

Other net losses (Tables)
12 Months Ended

Dec. 31, 2022

Other Income and Expenses [Abstract]

Schedule of Other Net Losses
Other net losses consist of the following:
2022 2021
Acquisition and transition-related costs $ 17,442 $ 14,507
Other (a) 3,949 8,442
$ 21,391 $ 22,949
(a)Other
Other losses primarily consist of costs pertaining to a condemnation proceeding, and miscellaneous asset write-downs, net of miscellaneous gains. Other losses in 2021 also included an adjustment to a regulatory liability pertaining to the true-up of prior period tracking accounts.

v3.23.1

Basic and diluted net earnings (loss) per share (Tables)
12 Months Ended

Dec. 31, 2022

Earnings Per Share, Basic and Diluted EPS [Abstract]

Schedule of Reconciliation of Net Income and Weighted Average Shares Used in Computation of Basic and Diluted Earnings per Share
The reconciliation of the net earnings and the weighted average shares used in the computation of basic and diluted earnings per share are as follows:
2022 2021
Net earnings (loss) attributable to shareholders of AQN $ (211,989) $ 264,859
Preferred shares, Series A dividend 4,786 4,942
Preferred shares, Series D dividend 3,934 4,061
Net earnings (loss) attributable to common shareholders of AQN – basic and diluted $ (220,709) $ 255,856
Weighted average number of shares
Basic 677,862,207 622,347,677
Effect of dilutive securities — 6,600,185
Diluted 677,862,207 628,947,862

v3.23.1

Segmented information (Tables)
12 Months Ended

Dec. 31, 2022

Segment Reporting [Abstract]

Schedule of Results of Operations and Assets for Segments

Year ended December 31, 2022
Regulated Services Group Renewable Energy Group Corporate Total
Revenue (1)(2)
$ 2,328,536 $ 350,939 $ — $ 2,679,475
Other revenue 55,732 28,447 1,501 85,680
Fuel, power and water purchased 824,670 41,826 — 866,496
Net revenue 1,559,598 337,560 1,501 1,898,659
Operating expenses 736,515 114,463 511 851,489
Administrative expenses 46,484 26,424 7,324 80,232
Depreciation and amortization 317,300 137,203 1,017 455,520
Asset impairment expense — 159,568 — 159,568
Loss on foreign exchange — — 13,833 13,833
459,299 (100,098) (21,184) 338,017
Gain on sale of renewable assets — 64,028 — 64,028
Operating income (loss) 459,299 (36,070) (21,184) 402,045
Interest expense (113,482) (64,285) (100,807) (278,574)
Income (loss) from long-term investments 21,884 15,254 (502,344) (465,206)
Other (14,765) (570) (12,598) (27,933)
Earnings (loss) before income taxes $ 352,936 $ (85,671) $ (636,933) $ (369,668)
Property, plant and equipment $ 8,554,938 $ 3,360,687 $ 29,260 $ 11,944,885
Investments carried at fair value 1,984 1,342,223 — 1,344,207
Equity-method investees 56,199 310,103 15,500 381,802
Total assets 12,109,575 5,251,933 266,105 17,627,613
Capital expenditures $ 908,676 $ 180,348 $ — $ 1,089,024
(1) Renewable Energy Group revenue includes $63,717 related to net hedging loss from energy derivative contracts and availability credits for the year ended December 31, 2022 that do not represent revenue recognized from contracts with customers.
(2) Regulated Services Group revenue includes $21,640 related to alternative revenue programs for the year ended December 31, 2022 that do not represent revenue recognized from contracts with customers.
21.Segmented information (continued)

Year ended December 31, 2021
Regulated Services Group Renewable Energy Group Corporate Total
Revenue (1)(2)
$ 1,944,171 $ 256,633 $ — $ 2,200,804
Other revenue 53,441 18,339 1,558 73,338
Fuel and power purchased 682,602 31,313 — 713,915
Net revenue 1,315,010 243,659 1,558 1,560,227
Operating expenses 597,850 104,262 16 702,128
Administrative expenses 37,179 28,298 1,249 66,726
Depreciation and amortization 280,452 121,414 1,097 402,963
Loss on foreign exchange — — 4,371 4,371
399,529 (10,315) (5,175) 384,039
Gain on sale of renewable assets — 29,063 — 29,063
Operating income (loss) 399,529 18,748 (5,175) 413,102
Interest expense (93,411) (71,598) (44,545) (209,554)
Income (loss) from long-term investments 18,306 84,046 (128,809) (26,457)
Other (24,177) (2,956) (7,726) (34,859)
Earnings (loss) before income taxes $ 300,247 $ 28,240 $ (186,255) $ 142,232
Property, plant and equipment $ 7,394,151 $ 3,615,915 $ 32,380 $ 11,042,446
Investments carried at fair value 2,296 1,846,160 — 1,848,456
Equity-method investees 37,492 375,460 20,898 433,850
Total assets 10,524,466 6,123,888 149,149 16,797,503
Capital expenditures $ 998,855 $ 338,637 $ 7,553 $ 1,345,045
(1) Renewable Energy Group revenue includes $57,018 related to net hedging loss from energy derivative contracts for the year ended December 31, 2021 that do not represent revenue recognized from contracts with customers.
(2) Regulated Services Group revenue includes $19,043 related to alternative revenue programs for the year ended December 31, 2021 that do not represent revenue recognized from contracts with customers.

Schedule of Information on Operations by Geographic Area Information on operations by geographic area is as follows:
2022 2021
Revenue
United States $ 2,232,959 $ 1,790,539
Canada 175,005 157,854
Other regions 357,191 325,749
$ 2,765,155 $ 2,274,142
Property, plant and equipment
United States $ 10,351,736 $ 9,464,716
Canada 848,560 882,454
Other regions 744,589 695,276
$ 11,944,885 $ 11,042,446
Intangible assets
United States $ 18,818 $ 23,575
Canada 19,038 21,780
Other regions 58,827 59,761
$ 96,683 $ 105,116

v3.23.1

Commitments and contingencies (Tables)
12 Months Ended

Dec. 31, 2022

Commitments and Contingencies Disclosure [Abstract]

Schedule of Estimates of Future Commitments
Detailed below are estimates of future commitments under these arrangements:
Year 1 Year 2 Year 3 Year 4 Year 5 Thereafter Total
Power purchase (i) $ 89,846 $ 32,490 $ 32,726 $ 12,274 $ 12,520 $ 142,586 $ 322,442
Natural gas supply and service agreements (ii) 113,775 81,719 57,014 40,372 31,457 188,138 512,475
Service agreements 67,477 57,886 55,835 49,596 46,511 298,516 575,821
Capital projects 7,163 — — — — — 7,163
Land easements 13,295 13,316 13,503 13,667 13,837 463,785 531,403
Total $ 291,556 $ 185,411 $ 159,078 $ 115,909 $ 104,325 $ 1,093,025 $ 1,949,304
(i) Power purchase: AQN’s electric distribution facilities have commitments to purchase physical quantities of power for load serving requirements. The commitment amounts included in the table above are based on market prices as of December 31, 2022. However, the effects of purchased power unit cost adjustments are mitigated through a purchased power rate-adjustment mechanism.
(ii) Natural gas supply and service agreements: AQN’s natural gas distribution facilities and thermal generation facilities have commitments to purchase physical quantities of natural gas under contracts for purposes of load serving requirements and of generating power.

v3.23.1

Non-cash operating items (Tables)
12 Months Ended

Dec. 31, 2022

Disclosure Changes In Non Cash Operating Items [Abstract]

Schedule of Changes in Non-Cash Operating Items
The changes in non-cash operating items consist of the following:
2022 2021
Accounts receivable $ (124,631) $ (56,751)
Fuel and natural gas in storage (21,140) (43,642)
Supplies and consumables inventory (24,088) 445
Income taxes recoverable 549 (3,025)
Prepaid expenses (4,269) (1,189)
Accounts payable 24,395 (33,399)
Accrued liabilities 127,076 31,845
Current income tax liability (2,741) 4,363
Asset retirements and environmental obligations (22,342) (1,185)
Net regulatory assets and liabilities (174,427) (419,484)
$ (221,618) $ (522,022)

v3.23.1

Financial instruments (Tables)
12 Months Ended

Dec. 31, 2022

Fair Value Disclosures [Abstract]

Schedule of Fair Value of Financial Instruments Fair value of financial instruments
December 31, 2022 Carrying
amount Fair
value Level 1 Level 2 Level 3
Long-term investments carried at fair value $ 1,344,207 $ 1,344,207 $ 1,270,138 $ — $ 74,083
Development loans and other receivables 53,680 50,300 — 50,300 —
Derivative instruments:
Energy contracts not designated as cash flow hedge 393 393 — — 393
Interest rate swap designated as a hedge 69,188 69,188 — 69,188 —
Interest rate cap not designated as a hedge 2,659 2,659 — 2,659 —
Congestion revenue rights not designated as a cash flow hedge 10,110 10,110 — — 10,110
Cross currency swap designated as a net investment hedge 1,267 1,267 — 1,267 —
Commodity contracts for regulated operations 283 283 — 283 —
Total derivative instruments 83,900 83,900 — 73,397 10,503
Total financial assets $ 1,481,787 $ 1,478,407 $ 1,270,138 $ 123,697 $ 84,586
Long-term debt $ 7,512,017 $ 6,699,031 $ 2,623,628 $ 4,075,403 $ —
Notes payable to related party 25,808 15,180 — 15,180 —
Convertible debentures 245 276 276 — —
Preferred shares, Series C 12,072 11,675 — 11,675 —
Derivative instruments:
Energy contracts designated as a cash flow hedge 120,284 120,284 — — 120,284
Energy contracts not designated as a cash flow hedge 8,617 8,617 — — 8,617
Cross-currency swap designated as a net investment hedge 24,371 24,371 — 24,371 —
Cross currency swap designated as a cash flow hedge 15,435 15,435 — 15,435 —
Commodity contracts for regulated operations 1,614 1,614 — 1,614 —
Total derivative instruments 170,321 170,321 — 41,420 128,901
Total financial liabilities $ 7,720,463 $ 6,896,483 $ 2,623,904 $ 4,143,678 $ 128,901
24.Financial instruments (continued)
(a)Fair value of financial instruments (continued)
December 31, 2021 Carrying
amount Fair
value Level 1 Level 2 Level 3
Long-term investment carried at fair value $ 1,848,456 $ 1,848,456 $ 1,753,210 $ — $ 95,246
Development loans and other receivables 32,261 33,286 — 33,286 —
Derivative instruments:
Energy contracts designated as a cash flow hedge 15,362 15,362 — — 15,362
Interest rate swap designated as a hedge 1,581 1,581 — 1,581 —
Cross-currency swap designated as a net investment hedge 1,958 1,958 — 1,958 —
Commodity contracts for regulated operations 1,721 1,721 — 1,721 —
Total derivative instruments 20,622 20,622 — 5,260 15,362
Total financial assets $ 1,901,339 $ 1,902,364 $ 1,753,210 $ 38,546 $ 110,608
Long-term debt $ 6,211,375 $ 6,543,933 $ 2,418,580 $ 4,125,352 $ —
Notes payable to related party 25,808 25,808 — 25,808 —
Convertible debentures 277 519 519 — —
Preferred shares, Series C 13,348 14,580 — 14,580 —
Derivative instruments:
Energy contracts designated as a cash flow hedge 60,462 60,462 — — 60,462
Energy contracts not designated as a cash flow hedge 1,169 1,169 — — 1,169
Cross-currency swap designated as a net investment hedge 50,258 50,258 — 50,258 —
Interest rate swaps designated as a hedge 7,008 7,008 — 7,008 —
Commodity contracts for regulated operations 1,348 1,348 — 1,348 —
Total derivative instruments 120,245 120,245 — 58,614 61,631
Total financial liabilities $ 6,371,053 $ 6,705,085 $ 2,419,099 $ 4,224,354 $ 61,631

Summary of Commodity Volumes Associated with Derivative Contracts
The following are commodity volumes, in dekatherms (“dths”), associated with the above derivative contracts:
2022
Financial contracts: Swaps
1,687,217
Options 35,824
1,723,041

Schedule of Long-Term Energy Derivative Contracts
The Company reduces the price risk on the expected future sale of power generation by entering into the following long-term energy derivative contracts. Upon the acquisition of the Sugar Creek Wind Facility in 2021 (note 3(f)), the Company redesignated a long-term energy derivative contract to mitigate the price risk on the expected future sale of power generation. The fair value of the derivative on the redesignation date will be amortized into earnings over the remaining life of the contract.
Notional quantity
(MW-hrs) Expiry Receive average
prices (per MW-hr) Pay floating price
(per MW-hr)
4,059,905 September 2030 $24.54 Illinois Hub
413,620 December 2028 $29.15 PJM Western HUB
1,977,766 December 2027 $22.05 NI HUB
1,665,318 December 2027 $36.46 ERCORT North HUB

Schedule of Derivative Financial Instruments Designated as Cash Flow Hedge, Effect on Consolidated Statement of Operations
The following table summarizes OCI attributable to derivative financial instruments designated as a cash flow hedge:
2022 2021
Effective portion of cash flow hedge $ (128,838) $ (97,103)
Amortization of cash flow hedge (12,180) (2,132)
Amounts reclassified from AOCI 46,723 44,904
OCI attributable to shareholders of AQN $ (94,295) $ (54,331)

Schedule of Effects on Statement of Operations of Derivative Financial Instruments Not Designated as Hedges
The effects on the consolidated statements of operations of derivative financial instruments not designated as hedges consist of the following:
2022 2021
Unrealized gain (loss) on derivative financial instruments:
Energy derivative contracts $ (945) $ (5,353)
Commodity contracts 185 —
Total unrealized loss on derivative financial instruments $ (760) $ (5,353)
Realized gain (loss) on derivative financial instruments:
Energy derivative contracts $ 6,939 $ (108)
Currency forward contract — 2,329
Interest rate swaps (7,185) —
Total realized gain (loss) on derivative financial instruments $ (246) $ 2,221
Loss on derivative financial instruments not accounted for as hedges (1,006) (3,132)
Amortization of AOCI gains frozen as a result of hedge dedesignation 3,465 3,712
$ 2,459 $ 580
Consolidated statements of operations classification:
Gain on derivative financial instruments $ 4,408 $ 4,403
Gain on foreign exchange — 2,329
Renewable energy sales 5,236 (6,152)
Reduction to gain on sale of renewable assets (7,185) —
$ 2,459 $ 580

Schedule of Maximum Credit Risk Exposure for Financial Instruments
As of December 31, 2022, the Company’s maximum exposure to credit risk for these financial instruments was as follows:
2022
Cash and cash equivalents and restricted cash $ 101,185
Accounts receivable 552,914
Allowance for doubtful accounts (24,857)
Notes receivable 53,680
$ 682,922

Schedule of Liabilities Maturity Profile
The Company’s liabilities mature as follows:
Due less
than 1 year Due 2 to 3
years Due 4 to 5
years Due after
5 years Total
Long-term debt obligations $ 1,128,660 $ 404,633 $ 1,984,855 $ 4,019,166 $ 7,537,314
Interest on long-term debt 310,863 447,227 386,560 3,936,205 5,080,855
Purchase obligations 741,888 — — — 741,888
Environmental obligation 9,326 18,084 1,915 19,021 48,346
Advances in aid of construction 1,554 — — 86,992 88,546
Derivative financial instruments:
Cross-currency swap 3,205 5,541 6,279 24,781 39,806
Energy derivative and commodity contracts 29,286 49,865 29,896 21,468 130,515
Contract adjustment payments on Green Equity Units 76,208 37,668 — — 113,876
Other obligations 37,209 6,392 5,080 271,962 320,643
Total obligations $ 2,338,199 $ 969,410 $ 2,414,585 $ 8,379,595 $ 14,101,789

v3.23.1

Notes to the Consolidated Financial Statements - Additional Information (Details)
12 Months Ended

Dec. 31, 2022

business_unit

Organization, Consolidation and Presentation of Financial Statements [Abstract]

Number of business units 2

v3.23.1

Accounts receivable - Additional Information (Detail) - USD ($)
$ in Thousands

Dec. 31, 2022

Dec. 31, 2021

Accounts, Notes, Loans and Financing Receivable [Line Items]

Allowance for doubtful accounts receivable $ 24,857 $ 19,327

Unbilled revenue

Accounts, Notes, Loans and Financing Receivable [Line Items]

Accounts receivable balances $ 149,015 $ 102,693

v3.23.1

Property, plant and equipment - Schedule of Plant, Property and Equipment (Detail) - USD ($)
$ in Thousands

Dec. 31, 2022

Dec. 31, 2021

Property, Plant and Equipment [Line Items]

Cost $ 14,003,548 $ 12,630,666

Accumulated depreciation 2,058,663 1,588,220

Net book value 11,944,885 11,042,446

Land

Property, Plant and Equipment [Line Items]

Cost 113,153 114,821

Accumulated depreciation 0 0

Net book value 113,153 114,821

Equipment

Property, Plant and Equipment [Line Items]

Cost 111,707 101,971

Accumulated depreciation 50,904 56,464

Net book value 60,803 45,507

Generation

Property, Plant and Equipment [Line Items]

Cost 4,119,514 4,187,197

Accumulated depreciation 1,016,784 751,219

Net book value 3,102,730 3,435,978

Generation | Construction in progress

Property, Plant and Equipment [Line Items]

Cost 196,287 148,302

Accumulated depreciation 0 0

Net book value 196,287 148,302

Utility plant

Property, Plant and Equipment [Line Items]

Cost 8,640,224 7,468,236

Accumulated depreciation 990,975 780,537

Net book value 7,649,249 6,687,699

Distribution and transmission | Construction in progress

Property, Plant and Equipment [Line Items]

Cost 822,663 610,139

Accumulated depreciation 0 0

Net book value $ 822,663 $ 610,139

v3.23.1

Property, plant and equipment - Additional Information (Detail) - USD ($)
$ in Thousands
12 Months Ended

Dec. 31, 2022

Dec. 31, 2021

Property, Plant, and Equipment Disclosure [Line Items]

Cost of plant in service $ 559,630 $ 557,954

Accumulated depreciation related to commonly owned facilities 75,820 59,857

Expenditures 110,268 143,255

Contribution received 1,299 6,376

Generation

Property, Plant, and Equipment Disclosure [Line Items]

Renewable generation assets related to facilities under capital lease and owned by consolidated VIE 111,192 114,868

Renewable generation assets related to facilities under capital lease and owned by consolidated VIE, accumulated depreciation 46,666 46,649

Depreciation expense 1,489 1,716

Regulated Services Group

Property, Plant, and Equipment Disclosure [Line Items]

Cost of distribution assets 3,076 3,076

Accumulated depreciation 2,041 1,665

Utility plant

Property, Plant, and Equipment Disclosure [Line Items]

Renewable generation assets related to facilities under capital lease and owned by consolidated VIE 2,033,391 2,018,039

Renewable generation assets related to facilities under capital lease and owned by consolidated VIE, accumulated depreciation $ 133,644 $ 72,484

v3.23.1

Property, plant and equipment - Interest and AFUDC Capitalized (Details) - USD ($)
$ in Thousands
12 Months Ended

Dec. 31, 2022

Dec. 31, 2021

Schedule of Capitalization [Line Items]

Total $ 12,703 $ 7,350

Non-regulated property

Schedule of Capitalization [Line Items]

Interest capitalized on non-regulated property 4,762 3,313

Interest expense

Schedule of Capitalization [Line Items]

AFUDC capitalized on regulated property: 6,040 3,208

Interest, dividend and other income

Schedule of Capitalization [Line Items]

AFUDC capitalized on regulated property: $ 1,901 $ 829

v3.23.1

Intangible assets and goodwill - Schedule of Intangible Assets (Details) - USD ($)
$ in Thousands

Dec. 31, 2022

Dec. 31, 2021

Finite-Lived Intangible Assets [Line Items]

Cost $ 155,212 $ 162,292

Accumulated amortization 58,529 57,176

Net book value 96,683 105,116

Power sales contracts

Finite-Lived Intangible Assets [Line Items]

Cost 56,926 58,112

Accumulated amortization 42,818 43,118

Net book value 14,108 14,994

Customer relationships

Finite-Lived Intangible Assets [Line Items]

Cost 77,850 78,140

Accumulated amortization 13,709 12,337

Net book value 64,141 65,803

Interconnection agreements

Finite-Lived Intangible Assets [Line Items]

Cost 10,098 15,072

Accumulated amortization 1,851 1,721

Net book value 8,247 13,351

Other

Finite-Lived Intangible Assets [Line Items]

Cost 10,338 10,968

Accumulated amortization 151 0

Net book value $ 10,187 $ 10,968

v3.23.1

Intangible assets and goodwill - Additional Information (Details)
$ in Thousands

Dec. 31, 2022

USD ($)

Finite-Lived Intangible Assets, Net, Amortization Expense, Fiscal Year Maturity [Abstract]

Estimated amortization expense for intangibles in year 1 $ 2,580

Estimated amortization expense for intangibles in year 2 2,572

Estimated amortization expense for intangibles in year 3 2,572

Estimated amortization expense for intangibles in year 4 2,572

Estimated amortization expense for intangibles in year 5 $ 2,572

v3.23.1

Intangible assets and goodwill - Schedule of Goodwill (Details) - USD ($)
$ in Thousands
12 Months Ended

Dec. 31, 2022

Dec. 31, 2021

Goodwill [Roll Forward]

Goodwill beginning of the period $ 1,201,244 $ 1,208,390

Business acquisitions (note 3) 123,751 5,535

Foreign exchange (4,416) (12,681)

Goodwill end of the period $ 1,320,579 $ 1,201,244

v3.23.1

Long-term investments - Schedule of Long-Term Investments (Detail) - USD ($)
$ in Thousands

Dec. 31, 2022

Dec. 31, 2021

Schedule of Equity Method Investments [Line Items]

Investments carried at fair value $ 1,344,207 $ 1,848,456

Equity-method investees 381,802 433,850

Other 27,600 30,508

Long-term investments 462,325 495,826

Notes Receivable | Development loans

Schedule of Equity Method Investments [Line Items]

Development loans receivable from equity-method investees 52,923 31,468

Atlantica

Schedule of Equity Method Investments [Line Items]

Investments carried at fair value 1,268,140 1,750,914

Atlantica Yield Energy Solutions Canada Inc.

Schedule of Equity Method Investments [Line Items]

Investments carried at fair value 74,083 95,246

Other

Schedule of Equity Method Investments [Line Items]

Investments carried at fair value $ 1,984 $ 2,296

v3.23.1

Long-term investments - Operating entities (Detail) - $ / MWh
3 Months Ended 12 Months Ended

Mar. 31, 2021

Dec. 31, 2022

Texas Coastal Wind Facilities

Schedule of Equity Method Investments [Line Items]

Equity method investment acquired (percent) 51.00% 51.00%

Wind facility capacity (megawatt AC) 861,000

Blue Hill Wind Facility

Schedule of Equity Method Investments [Line Items]

Equity method investment acquired (percent) 20.00%

Wind facility capacity (megawatt AC) 175,000

Red Lily Wind Facility

Schedule of Equity Method Investments [Line Items]

Equity method investment acquired (percent) 75.00%

Wind facility capacity (megawatt AC) 26,400

Val-Eo Wind Facility

Schedule of Equity Method Investments [Line Items]

Equity method investment acquired (percent) 50.00%

Wind facility capacity (megawatt AC) 24,000

v3.23.1

Long-term investments - Equity method investees (Detail) - USD ($)
$ in Thousands
12 Months Ended

Dec. 31, 2022

Dec. 31, 2021

Equity Method Investment [Roll Forward]

Carrying value, January 1 $ 433,850

Net loss attributable to AQN (21,416) $ (26,337)

Operating projects bought back by AQN 0 (129,075)

Dividend received (23,829) (29,818)

Impairment 0

Reclassification during the period (note 8(e)) 0 (25,634)

Carrying value, December 31 381,802 433,850

Investments in Significant Partnerships and Joint Ventures

Equity Method Investment [Roll Forward]

Carrying value, January 1 433,850 186,452

Additional Investments 110,441 418,434

Net loss attributable to AQN (21,416) (26,337)

Other comprehensive loss attributable to AQN (67,110) 7,733

Dividend received (1,183) (2,981)

Other 3,130 5,258

Carrying value, December 31 $ 381,802 $ 433,850

v3.23.1

Long-term investments - Investments in Significant Partnerships and Joint Ventures (Details) - USD ($)
$ in Thousands
12 Months Ended

Dec. 31, 2022

Dec. 31, 2021

Dec. 31, 2020

Equity Method Investment, Summarized Financial Information [Abstract]

Total assets $ 17,627,613 $ 16,797,503

AQN's investment carrying amount for the entities 381,802 433,850

Long-term debt 7,512,017 6,211,375

Income Statement [Abstract]

Revenue 2,765,155 2,274,142

Net loss (308,155) 185,657

Other comprehensive loss (90,036) (42,550)

Investments in Significant Partnerships and Joint Ventures

Equity Method Investment, Summarized Financial Information [Abstract]

Total assets 2,740,132 2,126,934

Total liabilities 1,507,079 945,971

Net assets 1,233,053 1,180,963

Income Statement [Abstract]

Revenue 65,025 20,262

Net loss (31,070) (46,293)

Other comprehensive loss (130,729) 15,177

Investments in Significant Partnerships and Joint Ventures | APUC

Income Statement [Abstract]

Net loss (21,416) (26,337)

Other comprehensive loss (67,110) 7,733

Investments in Significant Partnerships and Joint Ventures

Equity Method Investment, Summarized Financial Information [Abstract]

AQN's investment carrying amount for the entities 381,802 433,850 $ 186,452

Investments in Significant Partnerships and Joint Ventures | APUC

Equity Method Investment, Summarized Financial Information [Abstract]

AQN's ownership interest in the entities 332,663 327,555

Difference between investment carrying amount and underlying equity in net assets 49,139 106,295

AQN's investment carrying amount for the entities $ 381,802 $ 433,850

v3.23.1

Long-term investments - Combined Information for APUC's interest in VIE's (Details) - USD ($)
$ in Thousands
12 Months Ended

Dec. 31, 2022

Dec. 31, 2021

Variable Interest Entity [Line Items]

Interest income $ 107,143 $ 101,523

Impairment 0

Other

Variable Interest Entity [Line Items]

Interest income 330

Variable Interest Entity, Not Primary Beneficiary

Variable Interest Entity [Line Items]

Carrying amount 122,752 86,202

Development loans receivable 52,923 31,468

Performance guarantees and other commitments on behalf of VIEs 658,224 409,232

APUC's maximum exposure in regard to VIE's $ 833,899 $ 526,902

v3.23.1

Long-term debt - Bank Credit Facilities Available to AQN and its Operating Groups (Details) - USD ($)
$ in Thousands

Dec. 31, 2022

Dec. 31, 2021

Debt Disclosure [Abstract]

Revolving and term credit facilities $ 4,513,300 $ 3,217,000

Funds drawn on facilities/ commercial paper issued (1,532,500) (849,600)

Letters of credit issued (465,200) (317,200)

Liquidity available under the facilities 2,515,600 2,050,200

Undrawn portion of uncommitted letter of credit facilities (226,900) (224,000)

Cash and cash equivalents 57,623 125,157

Total liquidity and capital reserves $ 2,346,323 $ 1,951,357

v3.23.1

Long-term debt - Principal Payments (Detail)
$ in Thousands

Dec. 31, 2022

USD ($)

Long-term Debt, Fiscal Year Maturity [Abstract]

2023 $ 1,128,660

2024 359,371

2025 45,262

2026 1,265,711

2027 719,144

Thereafter 4,019,166

Total $ 7,537,314

v3.23.1

Long-term debt - Schedule of Interest Expense (Details) - USD ($)
$ in Thousands
12 Months Ended

Dec. 31, 2022

Dec. 31, 2021

Debt Disclosure [Abstract]

Long-term debt $ 261,535 $ 217,123

Commercial paper, credit facility draws and related fees 43,015 17,065

Accretion of fair value adjustments (16,547) (18,174)

Capitalized interest and AFUDC capitalized on regulated property (10,802) (6,521)

Other 1,373 61

Interest expense $ 278,574 $ 209,554

v3.23.1

Pension and other post-retirement benefits - Additional Information (Detail) - USD ($)
$ in Thousands
12 Months Ended

Dec. 31, 2022

Dec. 31, 2021

Dec. 31, 2020

Employee Benefits Disclosure [Line Items]

Defined contribution pension plan cost $ 12,126 $ 10,836

Accumulated benefit obligation for pension plan 815,589 1,080,685

Pension benefits

Employee Benefits Disclosure [Line Items]

Defined benefit plan, plan assets, amount 569,255 648,864 $ 629,157

Expected employer contributions for next year 22,386

OPEB

Employee Benefits Disclosure [Line Items]

Defined benefit plan, plan assets, amount 172,167 192,375 $ 176,616

Expected employer contributions for next year 9,819

Private Equity Funds | Level 3

Employee Benefits Disclosure [Line Items]

Defined benefit plan, plan assets, amount $ 21,904 $ 17,314

v3.23.1

Pension and other post-retirement benefits - Projected Benefit Obligations, Fair Value of Plan Assets, and Funded Status (Detail) - USD ($)
$ in Thousands
12 Months Ended

Dec. 31, 2022

Dec. 31, 2021

Change in plan assets

Non-current assets (note 11) $ 26,482 $ 23,630

Pension benefits

Change in projected benefit obligation

Projected benefit obligation, beginning of year 765,618 834,913

Projected benefit obligation assumed from business combination 87,933 0

Plan Settlements (112) (1,294)

Service cost 16,309 14,673

Interest cost 24,787 20,676

Actuarial gain (198,074) (36,597)

Contributions from retirees 0 0

Plan amendments 0 237

Medicare Part D 0 0

Benefits paid (68,197) (66,800)

Foreign exchange (129) (190)

Projected benefit obligation, end of year 628,135 765,618

Change in plan assets

Fair value of plan assets, beginning of year 648,864 629,157

Plan assets acquired in business combination 74,532 0

Actual return on plan assets (109,118) 58,721

Employer contributions 23,296 29,058

Plan Settlements (112) (1,294)

Contributions from retirees 0 0

Medicare Part D subsidy receipts 0 0

Benefits paid (68,197) (66,800)

Foreign exchange (10) 22

Fair value of plan assets, end of year 569,255 648,864

Unfunded status (58,880) (116,754)

Non-current assets (note 11) 12,264 11,751

Current liabilities (1,907) (1,902)

Non-current liabilities (69,237) (126,603)

Net amount recognized (58,880) (116,754)

OPEB

Change in projected benefit obligation

Projected benefit obligation, beginning of year 292,646 306,524

Projected benefit obligation assumed from business combination 5,195 0

Plan Settlements 0 0

Service cost 6,277 7,307

Interest cost 9,146 8,048

Actuarial gain (82,991) (18,977)

Contributions from retirees 2,220 2,040

Plan amendments (2,452) 310

Medicare Part D 367 373

Benefits paid (13,078) (12,979)

Foreign exchange 0 0

Projected benefit obligation, end of year 217,330 292,646

Change in plan assets

Fair value of plan assets, beginning of year 192,375 176,616

Plan assets acquired in business combination 8,577 0

Actual return on plan assets (30,105) 15,200

Employer contributions 11,811 11,178

Plan Settlements 0 0

Contributions from retirees 2,220 1,988

Medicare Part D subsidy receipts 367 372

Benefits paid (13,078) (12,979)

Foreign exchange 0 0

Fair value of plan assets, end of year 172,167 192,375

Unfunded status (45,163) (100,271)

Non-current assets (note 11) 14,218 11,879

Current liabilities (3,039) (699)

Non-current liabilities (56,342) (111,451)

Net amount recognized $ (45,163) $ (100,271)

v3.23.1

Pension and other post-retirement benefits - Benefit Obligations in Excess of Plan Assets (Details) - USD ($)
$ in Thousands

Dec. 31, 2022

Dec. 31, 2021

Pension benefits

Defined Benefit Plan Disclosure [Line Items]

Accumulated benefit obligation $ 413,041 $ 489,043

Fair value of plan assets 364,229 396,679

Projected benefit obligation 489,140 580,841

Fair value of plan assets 417,994 452,333

OPEB

Defined Benefit Plan Disclosure [Line Items]

Accumulated benefit obligation 198,463 274,649

Fair value of plan assets 139,368 162,592

Projected benefit obligation 198,463 274,649

Fair value of plan assets $ 139,368 $ 162,592

v3.23.1

Pension and other post-retirement benefits - Weighted Average Assumptions Used to Determine Net Benefit Obligation (Detail)
12 Months Ended

Dec. 31, 2022

Dec. 31, 2021

Pension benefits

Defined Benefit Plan Disclosure [Line Items]

Discount rate 5.48% 2.94%

Interest crediting rate (for cash balance plans) 4.50% 4.00%

Rate of compensation increase 3.70% 4.00%

OPEB

Defined Benefit Plan Disclosure [Line Items]

Discount rate 5.49% 3.00%

Health care cost trend rate

Before age 65 6.00% 5.88%

Age 65 and after 6.00% 5.88%

Assumed ultimate medical inflation rate 4.75% 4.75%

Year in which ultimate rate is reached 2033 2031

v3.23.1

Pension and other post-retirement benefits - Weighted Average Assumptions Used to Determine Net Benefit Cost (Detail)
12 Months Ended

Dec. 31, 2022

Dec. 31, 2021

Pension benefits

Defined Benefit Plan Disclosure [Line Items]

Discount rate 2.94% 2.49%

Expected return on assets 6.19% 6.20%

Rate of compensation increase 3.91% 3.99%

OPEB

Defined Benefit Plan Disclosure [Line Items]

Discount rate 3.00% 2.58%

Expected return on assets 6.48% 4.79%

Health care cost trend rate

Before Age 65 5.88% 5.12%

Age 65 and after 5.88% 5.12%

Assumed ultimate medical inflation rate 4.75% 4.05%

Year in which ultimate rate is reached 2031 2031

v3.23.1

Pension and other post-retirement benefits - Components of Net Benefit Costs for Pension Plans and OPEB Recorded as Part of Administrative Expenses (Detail) - USD ($)
$ in Thousands
12 Months Ended

Dec. 31, 2022

Dec. 31, 2021

Non-service costs

Non-service costs $ 10,950 $ 16,313

Pension benefits

Defined Benefit Plan Disclosure [Line Items]

Service cost 16,309 14,673

Non-service costs

Interest cost 24,787 20,676

Expected return on plan assets (41,226) (35,972)

Amortization of net actuarial loss 3,452 13,126

Amortization of prior service credits (1,584) (1,626)

Amortization due to plan settlements (15) 198

Impact of regulatory accounts 22,951 19,665

Non-service costs 8,365 16,067

Net benefit cost 24,674 30,740

OPEB

Defined Benefit Plan Disclosure [Line Items]

Service cost 6,277 7,307

Non-service costs

Interest cost 9,146 8,048

Expected return on plan assets (11,359) (10,052)

Amortization of net actuarial loss (56) 2,021

Amortization of prior service credits 24 11

Amortization due to plan settlements 0 0

Impact of regulatory accounts 4,829 218

Non-service costs 2,584 246

Net benefit cost $ 8,861 $ 7,553

v3.23.1

Pension and other post-retirement benefits - Fair Value of Investments by Asset Category (Details) - Level 1
$ in Thousands

Dec. 31, 2022

USD ($)

Defined Benefit Plan Disclosure [Line Items]

2022 $ 741,422

Percentage 100.00%

Equity securities

Defined Benefit Plan Disclosure [Line Items]

2022 $ 317,088

Percentage 43.00%

Debt securities

Defined Benefit Plan Disclosure [Line Items]

2022 $ 356,654

Percentage 48.00%

Other

Defined Benefit Plan Disclosure [Line Items]

2022 $ 67,680

Percentage 9.00%

v3.23.1

Pension and other post-retirement benefits- Change in Plan Assets (Details) - Level 3 - Private Equity Funds
$ in Thousands
12 Months Ended

Dec. 31, 2022

USD ($)

Defined Benefit Plan, Change in Fair Value of Plan Assets, Level 3 Reconciliation [Roll Forward]

Fair value of plan assets, beginning of year $ 17,314

Contributions into funds 4,781

Return on assets 2,094

Distributions (2,285)

Fair value of plan assets, end of year $ 21,904

v3.23.1

Pension and other post-retirement benefits - Expected Benefit Payments (Detail)
$ in Thousands

Dec. 31, 2022

USD ($)

Pension plan

Defined Benefit Plan Disclosure [Line Items]

2023 $ 48,174

2024 47,428

2025 49,794

2026 50,585

2027 50,433

2028-2032 259,082

OPEB

Defined Benefit Plan Disclosure [Line Items]

2023 11,483

2024 12,025

2025 12,548

2026 12,925

2027 13,479

2028-2032 $ 72,684

v3.23.1

Other assets - Schedule of Other Assets (Detail) - USD ($)
$ in Thousands

Dec. 31, 2022

Dec. 31, 2021

Deferred Costs, Capitalized, Prepaid, and Other Assets Disclosure [Abstract]

Restricted cash $ 43,562 $ 36,232

Pension and OPEB plan assets (note 10 26,482 23,630

Long-term deposits and cash collateral 22,537 14,713

Income taxes recoverable 7,100 7,649

Deferred financing costs 28,586 30,544

Other (b) 21,596 10,913

Total other assets 149,863 123,681

Less: current portion (22,564) (16,153)

Other assets (note 11) $ 127,299 $ 107,528

v3.23.1

Other long-term liabilities - Schedule of Long-Term Liabilities and Deferred Credits (Detail) - USD ($)
$ in Thousands

Dec. 31, 2022

Dec. 31, 2021

Dec. 31, 2020

Other Liabilities Disclosure [Abstract]

Contract adjustment payments $ 113,876 $ 187,580

Asset retirement obligations 116,584 142,147 $ 79,968

Advances in aid of construction 88,546 82,584

Environmental remediation obligation 42,457 55,224 69,383

Customer deposits 34,675 32,629

Unamortized investment tax credits 17,649 17,439

Deferred credits and contingent consideration 39,498 43,495

Preferred shares, Series C 12,072 13,348

Hook-up fees 32,463 21,904

Lease liabilities (note 1) 21,834 22,512

Contingent development support obligations 8,824 4,615

Note payable to related party 25,808 25,808 $ 30,493

Other 41,156 34,534

Other long-term liabilities 595,442 683,819

Less: current portion (134,212) (167,908)

Other long-term liabilities, excluding current $ 461,230 $ 515,911

v3.23.1

Other long-term liabilities - Asset Retirement Obligations (Details) - USD ($)
$ in Thousands
12 Months Ended

Dec. 31, 2022

Dec. 31, 2021

Asset Retirement Obligation, Roll Forward Analysis [Roll Forward]

Opening balance $ 142,147 $ 79,968

Obligation assumed 793 57,067

Retirement activities (27,980) (4,133)

Accretion 4,589 4,381

Change in cash flow estimates (2,965) 4,864

Closing balance $ 116,584 $ 142,147

v3.23.1

Other long-term liabilities - Changes in Environmental Remediation Obligation (Details) - USD ($)
$ in Thousands
12 Months Ended

Dec. 31, 2022

Dec. 31, 2021

Accrual for Environmental Loss Contingencies [Roll Forward]

Opening balance $ 55,224 $ 69,383

Remediation activities (5,243) (9,865)

Accretion 2,167 1,025

Changes in cash flow estimates 1,344 2,265

Revision in assumptions (11,035) (7,584)

Closing balance $ 42,457 $ 55,224

v3.23.1

Other long-term liabilities - Preferred Shares, Series C (Details) - USD ($)
$ in Thousands

Dec. 31, 2022

Dec. 31, 2021

Class of Stock [Line Items]

Total Preferred shares series C $ 12,072 $ 13,348

Preferred shares, Series C | Dividends Payable

Class of Stock [Line Items]

2023 1,245

2024 1,443

2025 1,459

2026 1,316

2027 1,262

Thereafter to 2031 4,654

Redemption amount 3,943

Estimated dividend and redemption payments 15,322

Less: amounts representing interest (3,250)

Total Preferred shares series C 12,072

Less current portion (1,245)

Preferred shares series C, noncurrent $ 10,827

v3.23.1

Shareholders' capital - Common Shares (Detail) - shares
12 Months Ended

Dec. 31, 2022

Dec. 31, 2021

Common Shares Rollforward

Beginning balance (in shares) 671,960,276 597,142,219

Public offering (in shares) 2,861,709 67,611,465

Dividend reinvestment plan (in shares) 7,676,666 6,184,686

Exercise of share-based awards (in shares) 1,115,398 1,020,020

Conversion of convertible debentures (in shares) 754 1,886

Ending balance (in shares) 683,614,803 671,960,276

v3.23.1

Shareholders' capital - Preferred Shares (Detail)
$ / shares in Units, $ in Thousands, $ in Thousands

Dec. 31, 2022

USD ($)

shares

Dec. 31, 2022

CAD ($)

$ / shares

shares

Dec. 31, 2021

USD ($)

Stockholders Equity Note [Line Items]

Preferred shares | $ $ 184,299 $ 184,299

Series A

Stockholders Equity Note [Line Items]

Preferred stock issued (in shares) | shares 4,800,000 4,800,000

Shares issued, price per share (USD and CAD per share) | $ / shares $ 25

Preferred shares $ 100,463 $ 116,546

Series D

Stockholders Equity Note [Line Items]

Preferred stock issued (in shares) | shares 4,000,000 4,000,000

Shares issued, price per share (USD and CAD per share) | $ / shares $ 25

Preferred shares $ 83,836 $ 97,259

v3.23.1

Shareholder's capital - Share-Based Compensation Expense (Detail) - USD ($)
$ in Thousands
12 Months Ended

Dec. 31, 2022

Dec. 31, 2021

Schedule Of Employee Service Share Based Compensation Expense Allocation [Line Items]

Total share-based compensation $ 10,920 $ 8,395

Share options

Schedule Of Employee Service Share Based Compensation Expense Allocation [Line Items]

Total share-based compensation 980 939

Director deferred share units

Schedule Of Employee Service Share Based Compensation Expense Allocation [Line Items]

Total share-based compensation 960 821

Employee share purchase

Schedule Of Employee Service Share Based Compensation Expense Allocation [Line Items]

Total share-based compensation 562 592

Performance and restricted share units

Schedule Of Employee Service Share Based Compensation Expense Allocation [Line Items]

Total share-based compensation $ 8,418 $ 6,043

v3.23.1

Shareholders' capital - Fair Value of Share Options Granted (Detail) - $ / shares
12 Months Ended

Dec. 31, 2022

Dec. 31, 2021

Equity [Abstract]

Risk-free interest rate 1.90% 1.10%

Expected volatility 23.00% 23.00%

Expected dividend yield 4.30% 4.10%

Expected life 5 years 6 months 5 years 6 months

Weighted average grant date fair value per option (in USD per share) $ 2.44 $ 2.46

v3.23.1

Shareholders' capital - Stock Option Activity (Detail) - CAD ($)
$ / shares in Units, $ in Thousands
12 Months Ended

Dec. 31, 2022

Dec. 31, 2021

Dec. 31, 2020

Number of awards

Beginning balance (in shares) 2,040,528 2,110,448

Granted (in shares) 646,090 437,006

Exercised (in shares) (40,074) (506,926)

Forfeited (in shares) (19,764) 0

Ending balance (in shares) 2,626,780 2,040,528 2,110,448

Exercisable (in shares) 2,052,946

Weighted average exercise price

Beginning balance (in USD per share) $ 15.45

Granted (in USD per share) 19.11 $ 19.64

Exercised (in USD per share) 13.92 13.92

Forfeited (in USD per share) 19.11 0

Ending balance (in USD per share) 16.02 $ 15.45

Exercisable (in USD per share) $ 17.35

Weighted average remaining contractual term (years)

Outstanding shares, weighted average remaining contractual term 5 years 7 months 17 days 6 years 1 month 9 days 6 years 6 months 18 days

Granted, weighted average remaining contractual term 7 years 2 months 19 days 7 years 2 months 19 days

Exercised shares, weighted average remaining contractual term 5 years 11 months 12 days 5 years 11 months 12 days

Beginning balance, aggregate intrinsic value $ 3,145 $ 11,604

Exercised, aggregate intrinsic value 103 1,453

Ending balance, aggregate intrinsic value $ 0 $ 3,145 $ 11,604

Exercisable , weighted average remaining contractual term 5 years 7 months 17 days

v3.23.1

Shareholder's capital - Performance Stock Units (Detail) - CAD ($)
$ / shares in Units, $ in Thousands
12 Months Ended

Dec. 31, 2022

Dec. 31, 2021

Dec. 31, 2020

Weighted average remaining contractual term (years)

Weighted average remaining contractual term, Exercisable 5 years 7 months 17 days

Performance and restricted share units

Number of awards

Beginning balance (in shares) 2,443,672 2,721,207

Granted, including dividends (in shares) 1,090,457 805,433

Exercised (in shares) (1,221,620) (865,067)

Forfeited (in shares) (202,799) (217,901)

Ending balance (in shares) 2,109,710 2,443,672 2,721,207

Exercisable (in shares) 769,458

Weighted average grant-date fair value

Beginning balance (in USD per share) $ 18.07 $ 16.58

Granted, including dividends (in USD per share) 17.99 19.94

Exercised (in USD per share) 12.62 13.79

Forfeited (in USD per share) 18.94 18.64

Ending balance (in USD per share) 18.38 $ 18.07 $ 16.58

Exercisable (in USD per share) $ 18.70

Weighted average remaining contractual term (years)

Outstanding, Weighted average remaining contractual term 1 year 9 months 3 days 1 year 8 months 19 days 11 months 4 days

Granted, including dividends, Weighted average remaining contractual term 2 years 2 years 9 months 7 days

Weighted average remaining contractual term, Exercisable 1 month 6 days

Outstanding, aggregate intrinsic value $ 18,608 $ 44,646 $ 54,560

Granted, including dividends, aggregate intrinsic value 17,524 12,881

Exercised, aggregate intrinsic value 23,636 17,005

Forfeited, aggregate intrinsic value 418 $ 3,981

Exercisable, aggregate intrinsic value $ 6,787

v3.23.1

Shareholder's capital - Bonus Deferral RSUs (Detail) - shares
12 Months Ended

Dec. 31, 2022

Dec. 31, 2021

Treasury Stock, Common

Share-based Compensation Arrangement by Share-based Payment Award [Line Items]

Shares issued from treasury to settles RSUs and PSUs (in shares) 82,886 70,571

Common shares

Share-based Compensation Arrangement by Share-based Payment Award [Line Items]

Equity other than options settled at cash value for payment of the exercise price and for tax withholdings (in shares) 95,482 81,993

Retirement Restricted Share Units

Share-based Compensation Arrangement by Share-based Payment Award [Line Items]

Awards vested (percent) 100.00%

Bonus Deferral Restricted Stock Units

Share-based Compensation Arrangement by Share-based Payment Award [Line Items]

Shares issued during period (in shares) 55,445 56,686

Deferred Share Units

Share-based Compensation Arrangement by Share-based Payment Award [Line Items]

Shares issued during period (in shares) 645,714 530,378

Common stock, shares issued (in shares) 178,368 152,564

Awards outstanding (in shares) 158,486 281,411

v3.23.1

Dividends (Detail)
$ / shares in Units, $ / shares in Units, $ in Thousands, $ in Thousands
12 Months Ended

Dec. 31, 2022

USD ($)

$ / shares

Dec. 31, 2022

CAD ($)

$ / shares

Dec. 31, 2021

USD ($)

$ / shares

Dec. 31, 2021

CAD ($)

$ / shares

Dividends [Line Items]

Dividend declared for common share holders | $ $ 486,043 $ 423,023

Cash dividend declared per common share (USD per share) | $ / shares $ 0.7130 $ 0.6669

Preferred shares, Series A

Dividends [Line Items]

Dividends declared for preferred share holders | $ $ 6,194 $ 6,194

Dividend declared per preferred share (CAD per share) | $ / shares $ 1.2905 $ 1.2905

Preferred shares, Series D

Dividends [Line Items]

Dividends declared for preferred share holders | $ $ 5,091 $ 5,091

Dividend declared per preferred share (CAD per share) | $ / shares $ 1.2728 $ 1.2728

v3.23.1

Related party transactions (Detail) - USD ($)
$ in Thousands
3 Months Ended 12 Months Ended

Sep. 30, 2021

Dec. 31, 2022

Dec. 31, 2021

Dec. 31, 2020

Transactions with Third Party [Line Items]

Note payable to related party $ 25,808 $ 25,808 $ 30,493

AAGES Spain

Transactions with Third Party [Line Items]

Acquired assets $ 2,662

Working capital 1,507

Equity Method Investee

Transactions with Third Party [Line Items]

Reimbursement of expenses 63,861 25,778

Development fees 12,628 2,036

Note payable to related party 25,808 $ 30,493

Abengoa

Transactions with Third Party [Line Items]

Option to purchase interest in joint venture 1,500

Abengoa | AAGES Spain

Transactions with Third Party [Line Items]

Loans related to parties $ 3,089

Atlantica | Related Party

Transactions with Third Party [Line Items]

Purchases from related party 23,863

Gain on sale with related party $ 1,200 878

Contingent consideration $ 2,600

v3.23.1

Non-controlling interests and redeemable non-controlling interests - Net Loss Attributable to Non-Controlling Interest (Details) - USD ($)
$ in Thousands
12 Months Ended

Dec. 31, 2022

Dec. 31, 2021

Noncontrolling Interest [Line Items]

Net earnings attributable to NCI $ 111,323 $ 89,637

Redeemable non-controlling interest, held by related party (15,157) (10,435)

Net effect of non-controlling interests 96,166 79,202

Tax Equity Partnership Units

Noncontrolling Interest [Line Items]

Net earnings attributable to NCI 108,695 88,417

Redeemable Tax Equity Partnership Units

Noncontrolling Interest [Line Items]

Net earnings attributable to NCI 6,298 6,902

Non-controlling interests

Noncontrolling Interest [Line Items]

Net earnings attributable to NCI $ (3,670) $ (5,682)

v3.23.1

Non-controlling interests and redeemable non-controlling interests - Change in Redeemable non-controlling Interest (Details) - USD ($)
$ in Thousands
12 Months Ended

Dec. 31, 2022

Dec. 31, 2021

Increase (Decrease) in Temporary Equity [Roll Forward]

Opening balance $ 12,989 $ 20,859

Net earnings attributable to NCI (6,298) (6,902)

Contributions, net of costs 5,000 0

Dividends and distributions declared (171) (968)

Closing balance 11,520 12,989

Related Party

Increase (Decrease) in Temporary Equity [Roll Forward]

Opening balance 306,537 306,316

Net earnings attributable to NCI 15,157 10,435

Contributions, net of costs 0 0

Dividends and distributions declared (13,838) (10,214)

Closing balance $ 307,856 $ 306,537

v3.23.1

Income taxes - Additional Information (Detail) - USD ($)
$ in Thousands
12 Months Ended

Dec. 31, 2022

Dec. 31, 2021

Dec. 31, 2020

Income Tax Disclosure [Abstract]

Canadian enacted statutory rate (percent) 26.50% 26.50%

Valuation allowance for deferred tax assets $ 107,583 $ 27,471 $ 29,824

Undistributed earnings of foreign subsidiaries $ 824,052

v3.23.1

Income taxes - Provision for Income Taxes (Detail) - USD ($)
$ in Thousands
12 Months Ended

Dec. 31, 2022

Dec. 31, 2021

Income Tax Disclosure [Abstract]

Expected income tax recovery at Canadian statutory rate $ (97,962) $ 37,691

Increase (decrease) resulting from:

Effect of differences in tax rates on transactions in and within foreign jurisdictions and change in tax rates (55,315) (47,600)

Adjustments from investments carried at fair value 51,314 2,709

Non-controlling interests share of income 30,025 25,135

Change in valuation allowance 41,702 (118)

Non-deductible acquisition costs 1,341 3,733

Acquisition related state deferred tax adjustments 5,998 0

Capital gain rate differential on disposal of renewable assets (7,340) 0

Tax credits (18,440) (49,415)

Adjustment relating to prior periods (1,390) 1,333

Deferred income taxes on regulated income recorded as regulatory assets (2,155) (3,807)

Amortization and settlement of excess deferred income tax (14,855) (16,778)

Other 5,564 3,692

Total $ (61,513) $ (43,425)

v3.23.1

Income taxes - Income (Loss) Before Taxes (Detail) - USD ($)
$ in Thousands
12 Months Ended

Dec. 31, 2022

Dec. 31, 2021

Schedule of Components of Income Before Income Tax Expense (Benefit) [Line Items]

Income/(loss) before taxes $ (369,668) $ 142,232

Canada

Schedule of Components of Income Before Income Tax Expense (Benefit) [Line Items]

Income/(loss) before taxes (363,050) (60,848)

U.S.

Schedule of Components of Income Before Income Tax Expense (Benefit) [Line Items]

Income/(loss) before taxes (37,322) 153,719

Other regions

Schedule of Components of Income Before Income Tax Expense (Benefit) [Line Items]

Income/(loss) before taxes $ 30,704 $ 49,361

v3.23.1

Income taxes - Income Tax Expense (Recovery) Attributable to Income (Loss) (Detail) - USD ($)
$ in Thousands
12 Months Ended

Dec. 31, 2022

Dec. 31, 2021

Income Tax Expenses [Line Items]

Current $ 7,843 $ 7,237

Deferred (69,356) (50,662)

Total (61,513) (43,425)

Canada

Income Tax Expenses [Line Items]

Current 4,184 4,560

Deferred (74,595) (33,993)

Total (70,411) (29,433)

United States

Income Tax Expenses [Line Items]

Current 1,579 1,024

Deferred 6,183 (19,772)

Total 7,762 (18,748)

Other regions

Income Tax Expenses [Line Items]

Current 2,080 1,653

Deferred (944) 3,103

Total $ 1,136 $ 4,756

v3.23.1

Income taxes - Tax Effect on Significant Portions of Deferred Tax Assets and Deferred Tax Liabilities (Detail) - USD ($)
$ in Thousands

Dec. 31, 2022

Dec. 31, 2021

Dec. 31, 2020

Deferred tax assets:

Non-capital loss, investment tax credits, currently non-deductible interest expenses, and financing costs $ 878,000 $ 761,666

Pension and OPEB 16,845 46,580

Environmental obligation 12,118 15,271

Regulatory liabilities 156,285 166,939

Other 61,917 64,460

Total deferred income tax assets 1,125,165 1,054,916

Less: valuation allowance (107,583) (27,471) $ (29,824)

Total deferred tax assets 1,017,582 1,027,445

Deferred tax liabilities:

Property, plant and equipment 846,331 782,829

Outside basis differentials 315,581 412,665

Regulatory accounts 303,059 300,072

Other 33,834 30,471

Total deferred tax liabilities 1,498,805 1,526,037

Net deferred tax liabilities (481,223) (498,592)

Deferred tax assets 84,416 31,595

Deferred tax liabilities $ (565,639) $ (530,187)

v3.23.1

Income taxes - Summary of Valuation Allowance for Deferred Tax Assets (Details) - USD ($)
$ in Thousands
12 Months Ended

Dec. 31, 2022

Dec. 31, 2021

Deferred Tax Assets, Valuation Allowance [Roll Forward]

Beginning balance $ 27,471 $ 29,824

Charged to income tax expense (recovery) 41,702 (118)

Charged (reduction) to OCI 40,613 (1,707)

Reductions to other accounts (2,203) (528)

Ending balance $ 107,583 $ 27,471

v3.23.1

Other net losses Other Losses (Details) - USD ($)
$ in Thousands
12 Months Ended

Dec. 31, 2022

Dec. 31, 2021

Other Income and Expenses [Abstract]

Impairment of assets $ 235,478 $ 0

Acquisition and transition-related costs 17,442 14,507

Other 3,949 8,442

Other losses $ 21,391 $ 22,949

v3.23.1

Basic and diluted net earnings (loss) per share - Schedule of Earnings per Share (Detail) - USD ($)
12 Months Ended

Dec. 31, 2022

Dec. 31, 2021

Class of Stock [Line Items]

Net earnings (loss) attributable to shareholders of AQN $ (211,989,000) $ 264,859,000

Series A and D Preferred shares dividend 8,720,000 9,003,000

Net earnings (loss) attributable to common shareholders of AQN – basic (in shares) (220,709,000) 255,856,000

Net earnings (loss) attributable to common shareholders of AQN – diluted (in shares) $ (220,709,000) $ 255,856,000

Weighted average number of shares

Basic (in shares) 677,862,207 622,347,677

Effect of dilutive securities (in shares) 0 6,600,185

Diluted (in shares) 677,862,207 628,947,862

Preferred shares, Series A dividend

Class of Stock [Line Items]

Series A and D Preferred shares dividend $ 4,786,000 $ 4,942,000

Preferred shares, Series D dividend

Class of Stock [Line Items]

Series A and D Preferred shares dividend $ 3,934,000 $ 4,061,000

v3.23.1

Basic and diluted net earnings (loss) per share - Additional Information (Detail)
12 Months Ended

Dec. 31, 2021

shares

Options and Convertible Debentures

Class of Stock [Line Items]

Anti-dilutive convertible debentures (in shares) 437,006

v3.23.1

Segmented information - Additional Information (Detail)
12 Months Ended

Dec. 31, 2022

segment

business_unit

Segment Reporting [Abstract]

Number of business units | business_unit 2

Number of reportable segments | segment 2

v3.23.1

Segmented information - Information on Operations by Geographic Area (Detail) - USD ($)
$ in Thousands
12 Months Ended

Dec. 31, 2022

Dec. 31, 2021

Segment Reporting Information [Line Items]

Revenue $ 2,765,155 $ 2,274,142

Property, plant and equipment 11,944,885 11,042,446

Intangible assets 96,683 105,116

United States

Segment Reporting Information [Line Items]

Revenue 2,232,959 1,790,539

Property, plant and equipment 10,351,736 9,464,716

Intangible assets 18,818 23,575

Canada

Segment Reporting Information [Line Items]

Revenue 175,005 157,854

Property, plant and equipment 848,560 882,454

Intangible assets 19,038 21,780

Other regions

Segment Reporting Information [Line Items]

Revenue 357,191 325,749

Property, plant and equipment 744,589 695,276

Intangible assets $ 58,827 $ 59,761

v3.23.1

Commitments and contingencies - Additional Information (Details)
$ in Thousands

Aug. 02, 2022

USD ($)

Dec. 31, 2022

lawsuit

Commitments Disclosure [Line Items]

Attorney’s fees and litigation costs | $ $ 13,222

Mountain View Fire

Commitments Disclosure [Line Items]

Number of active lawsuits 17

Number of lawsuits filed by groups of individual plaintiffs 12

Number of lawsuits filed by insurance companies 4

v3.23.1

Commitments and contingencies - Estimates of Future Commitments (Detail)
$ in Thousands

Dec. 31, 2022

USD ($)

Commitments Disclosure [Line Items]

Year 1 $ 291,556

Year 2 185,411

Year 3 159,078

Year 4 115,909

Year 5 104,325

Thereafter 1,093,025

Total 1,949,304

Power purchase

Commitments Disclosure [Line Items]

Year 1 89,846

Year 2 32,490

Year 3 32,726

Year 4 12,274

Year 5 12,520

Thereafter 142,586

Total 322,442

Gas supply and service agreements

Commitments Disclosure [Line Items]

Year 1 113,775

Year 2 81,719

Year 3 57,014

Year 4 40,372

Year 5 31,457

Thereafter 188,138

Total 512,475

Service agreements

Commitments Disclosure [Line Items]

Year 1 67,477

Year 2 57,886

Year 3 55,835

Year 4 49,596

Year 5 46,511

Thereafter 298,516

Total 575,821

Capital projects

Commitments Disclosure [Line Items]

Year 1 7,163

Year 2 0

Year 3 0

Year 4 0

Year 5 0

Thereafter 0

Total 7,163

Land easements and others

Commitments Disclosure [Line Items]

Year 1 13,295

Year 2 13,316

Year 3 13,503

Year 4 13,667

Year 5 13,837

Thereafter 463,785

Total $ 531,403

v3.23.1

Non-cash operating items - Changes in Non-Cash Operating Items (Detail) - USD ($)
$ in Thousands
12 Months Ended

Dec. 31, 2022

Dec. 31, 2021

Disclosure Changes In Non Cash Operating Items [Abstract]

Accounts receivable $ (124,631) $ (56,751)

Fuel and natural gas in storage (21,140) (43,642)

Supplies and consumables inventory (24,088) 445

Income taxes recoverable 549 (3,025)

Prepaid expenses (4,269) (1,189)

Accounts payable 24,395 (33,399)

Accrued liabilities 127,076 31,845

Current income tax liability (2,741) 4,363

Asset retirements and environmental obligations (22,342) (1,185)

Net regulatory assets and liabilities (174,427) (419,484)

Changes in non-cash operating items $ (221,618) $ (522,022)

v3.23.1

Financial instruments - Summary of Commodity Volumes Associated with Derivative Contracts (Detail)

Dec. 31, 2022

MMBTU

Derivative [Line Items]

Commodity volumes, gas 1,723,041

Financial contracts: Swaps

Derivative [Line Items]

Commodity volumes, gas 1,687,217

Options

Derivative [Line Items]

Commodity volumes, gas 35,824

v3.23.1

Financial instruments - Long-term Energy Derivative Contracts (Detail) - Cash flow hedge

Dec. 31, 2022

MWh

$ / MWh

Illinois Hub, Expiry September 2030

Derivative [Line Items]

Notional quantity (MW-hrs) | MWh 4,059,905

Receive average prices (per MW-hr) | $ / MWh 24.54

PJM Western HUB, Expiry December 2028

Derivative [Line Items]

Notional quantity (MW-hrs) | MWh 413,620

Receive average prices (per MW-hr) | $ / MWh 29.15

NI HUB, Expiry December 2027

Derivative [Line Items]

Notional quantity (MW-hrs) | MWh 1,977,766

Receive average prices (per MW-hr) | $ / MWh 22.05

ERCOT North HUB, Expiry December 2027

Derivative [Line Items]

Notional quantity (MW-hrs) | MWh 1,665,318

Receive average prices (per MW-hr) | $ / MWh 36.46

v3.23.1

Financial instruments - Derivative Financial Instruments Designated as Cash Flow Hedge, Effect on Statement of Operations (Detail) - USD ($)
$ in Thousands
12 Months Ended

Dec. 31, 2022

Dec. 31, 2021

Fair Value Disclosures [Abstract]

Effective portion of cash flow hedge $ (128,838) $ (97,103)

Amortization of cash flow hedge (12,180) (2,132)

Amounts reclassified from AOCI 46,723 44,904

OCI attributable to shareholders of AQN $ (94,295) $ (54,331)

v3.23.1

Financial instruments - Maximum Credit Risk for these Financial Instruments (Detail)
$ in Thousands

Dec. 31, 2022

USD ($)

Fair Value Disclosures [Abstract]

Cash and cash equivalents and restricted cash $ 101,185

Accounts receivable 552,914

Allowance for doubtful accounts (24,857)

Notes receivable 53,680

Maximum exposure to credit risk for financial instruments $ 682,922

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Cover Page - shares	12 Months Ended
Cover Page - shares	Dec. 31, 2022	Dec. 31, 2021	Dec. 31, 2020
Entity Information [Line Items]
Document Type	40-F/A
Document Registration Statement	false
Document Annual Report	true
Document Period End Date	Dec. 31, 2022
Current Fiscal Year End Date	--12-31
Entity File Number	001-37946
Entity Registrant Name	ALGONQUIN POWER & UTILITIES CORP.
Entity Incorporation, State or Country Code	Z4
Entity Address, Address Line One	354 Davis Road
Entity Address, City or Town	Oakville
Entity Address, State or Province	ON
Entity Address, Postal Zip Code	L6J 2X1
Entity Address, Country	CA
City Area Code	905
Local Phone Number	465-4500
Annual Information Form	true
Audited Annual Financial Statements	true
Entity Common Stock, Shares Outstanding	683,614,803	671,960,276	597,142,219
Entity Current Reporting Status	Yes
Entity Interactive Data Current	Yes
Entity Emerging Growth Company	false
ICFR Auditor Attestation Flag	true
Entity Central Index Key	0001174169
Amendment Flag	false
Document Fiscal Period Focus	FY
Document Fiscal Year Focus	2022
6.875% Fixed-to-Floating Subordinated Notes - Series 2018-A due October 17, 2078
Entity Information [Line Items]
Title of 12(b) Security	6.875% Fixed-to-Floating Subordinated Notes - Series 2018-A due October 17, 2078
Trading Symbol	AQNA
Security Exchange Name	NYSE
6.20% Fixed-to-Floating Subordinated Notes - Series 2019-A due July 1, 2079
Entity Information [Line Items]
Title of 12(b) Security	6.20% Fixed-to-Floating Subordinated Notes - Series 2019-A due July 1, 2079
Trading Symbol	AQNB
Security Exchange Name	NYSE
Common shares
Entity Information [Line Items]
Title of 12(b) Security	Common shares, no par value
Trading Symbol	AQN
Security Exchange Name	NYSE
Corporate Units
Entity Information [Line Items]
Title of 12(b) Security	Corporate Units
Trading Symbol	AQNU
Security Exchange Name	NYSE
Rights to Purchase One Common Share of the Company
Entity Information [Line Items]
Title of 12(b) Security	Rights to Purchase One Common Share of the Company
Trading Symbol	N/A
Security Exchange Name	NYSE
Business Contact
Entity Information [Line Items]
Entity Address, Address Line One	111 Eighth Avenue
Entity Address, City or Town	New York
Entity Address, State or Province	NY
Entity Address, Postal Zip Code	10011
City Area Code	212
Local Phone Number	894-8940
Contact Personnel Name	CT Corporation System

Audit Information	12 Months Ended
Audit Information	Dec. 31, 2022
Audit Information [Abstract]
Auditor Name	Ernst & Young LLP
Auditor Location	Toronto, Canada
Auditor Firm ID	1263

Consolidated Statements of Operations - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2022	Dec. 31, 2021
Revenue
Other revenue	$ 2,765,155	$ 2,274,142
Expenses
Administrative expenses	80,232	66,726
Depreciation and amortization	455,520	402,963
Asset impairment charge (note 5)	159,568	0
Loss on foreign exchange	13,833	4,371
Costs and expenses, total	2,427,138	1,890,103
Gain on sale of renewable assets (notes 3(a) and 16(c))	64,028	29,063
Operating income (loss)	402,045	413,102
Interest expense	(278,574)	(209,554)
Fair value change, income (loss) and impairment charge on long-term investments (note 8)	(465,206)	(26,457)
Other net losses (note 19)	(21,391)	(22,949)
Pension and other post-employment non-service costs (note 10)	(10,950)	(16,313)
Gain on derivative financial instruments (note 24(b)(iv))	4,408	4,403
Nonoperating income (expense)	(771,713)	(270,870)
Income (loss) before income taxes	(369,668)	142,232
Income tax recovery (expense) (note 18)
Current	(7,843)	(7,237)
Deferred	69,356	50,662
Income tax expense	61,513	43,425
Net earnings (loss)	(308,155)	185,657
Non-controlling interests	111,323	89,637
Non-controlling interests held by related party	(15,157)	(10,435)
Net effect of non-controlling interests	96,166	79,202
Net earnings (loss) attributable to shareholders of Algonquin Power & Utilities Corp.	(211,989)	264,859
Preferred shares, Series A and preferred shares, Series D dividend (note 15)	8,720	9,003
Net earnings (loss) attributable to common shareholders of Algonquin Power & Utilities Corp.	$ (220,709)	$ 255,856
Basic net earnings (loss) per share (USD per share)	$ (0.33)	$ 0.41
Diluted net earnings (loss) per share (USD per share)	$ (0.33)	$ 0.41
Regulated electricity distribution
Revenue
Other revenue	$ 1,277,409	$ 1,183,399
Expenses
Expenses	465,570	475,764
Regulated natural gas distribution
Revenue
Other revenue	686,744	525,897
Expenses
Expenses	340,792	194,174
Regulated water reclamation and distribution
Revenue
Other revenue	364,383	234,875
Expenses
Expenses	18,308	12,664
Non-regulated energy sales
Revenue
Other revenue	350,939	256,633
Expenses
Expenses	41,826	31,313
Other revenue
Revenue
Other revenue	85,680	73,338
Operating expenses
Expenses
Expenses	$ 851,489	$ 702,128

Consolidated Statements of Comprehensive Income - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2022	Dec. 31, 2021
Statement of Comprehensive Income [Abstract]
Net earnings (loss)	$ (308,155)	$ 185,657
Other comprehensive income (loss) (“OCI”):
Foreign currency translation adjustment, net of tax expense of $2,423 and recovery of $3,219, respectively (notes 24(b)(iii) and 24(b)(iv))	(23,502)	(30,270)
Change in fair value of cash flow hedges, net of tax expense of $20,644 and recovery of $22,077, respectively (note 24(b)(ii))	(94,295)	(54,331)
Change in pension and other post-employment benefits, net of tax expense of $8,330 and $9,176, respectively (note 10)	27,761	42,051
OCI, net of tax	(90,036)	(42,550)
Comprehensive income (loss)	(398,191)	143,107
Comprehensive loss attributable to the non-controlling interests	(97,816)	(78,953)
Comprehensive income (loss) attributable to shareholders of Algonquin Power & Utilities Corp.	$ (300,375)	$ 222,060

Consolidated Balance Sheets - USD ($) $ in Thousands	Dec. 31, 2022	Dec. 31, 2021
Current assets:
Cash and cash equivalents	$ 57,623	$ 125,157
Trade and other receivables, net (note 4)	528,057	403,426
Fuel and natural gas in storage	95,350	74,209
Supplies and consumables inventory	129,571	103,552
Regulatory assets (note 7)	190,393	158,212
Prepaid expenses	58,653	54,548
Derivative instruments (note 24)	12,270	3,486
Other assets (note 11)	22,564	16,153
Assets, current, total	1,094,481	938,743
Property, plant and equipment, net (note 5)	11,944,885	11,042,446
Intangible assets, net (note 6)	96,683	105,116
Goodwill (note 6)	1,320,579	1,201,244
Regulatory assets (note 7)	1,081,108	1,009,413
Long-term investments (note 8)
Investments carried at fair value	1,344,207	1,848,456
Other long-term investments	462,325	495,826
Derivative instruments (note 24)	71,630	17,136
Deferred income taxes (note 18)	84,416	31,595
Other assets (note 11)	127,299	107,528
Assets	17,627,613	16,797,503
Current liabilities:
Accounts payable	186,080	185,291
Accrued liabilities	555,792	428,733
Dividends payable (note 15)	125,655	114,544
Regulatory liabilities (note 7)	69,865	65,809
Long-term debt (note 9)	423,274	356,397
Other long-term liabilities (note 12)	134,212	167,908
Derivative instruments (note 24)	32,491	38,569
Other liabilities	7,091	7,461
Liabilities, current, total	1,534,460	1,364,712
Long-term debt (note 9)	7,088,743	5,854,978
Regulatory liabilities (note 7)	558,317	510,380
Deferred income taxes (note 18)	565,639	530,187
Derivative instruments (note 24)	137,830	81,676
Pension and other post-employment benefits obligation (note 10)	125,579	238,054
Other long-term liabilities (note 12)	461,230	515,911
Liabilities, noncurrent, total	8,937,338	7,731,186
Redeemable non-controlling interests (note 17)
Redeemable non-controlling interest, held by related party	307,856	306,537
Redeemable non-controlling interests	11,520	12,989
Redeemable non-controlling interests, total	319,376	319,526
Equity:
Preferred shares	184,299	184,299
Common shares (note 13(a))	6,183,943	6,032,792
Additional paid-in capital	9,413	2,007
Deficit	(997,945)	(288,424)
Accumulated other comprehensive loss (“AOCI”) (note 14)	(160,063)	(71,677)
Total equity attributable to shareholders of Algonquin Power & Utilities Corp.	5,219,647	5,858,997
Non-controlling interests (note 17)
Non-controlling interests - tax equity partnership units	1,225,608	1,377,117
Other non-controlling interests	333,362	64,807
Non-controlling interest, held by related party	57,822	81,158
Non-controlling interests, total	1,616,792	1,523,082
Total equity	6,836,439	7,382,079
Commitments and contingencies (note 22)
Liabilities and equity, total	$ 17,627,613	$ 16,797,503

Consolidated Statement of Equity - USD ($) $ in Thousands	Total	Common shares	Preferred shares	Additional paid-in capital	Retained earnings (deficit)	AOCI	Non- controlling interests
Beginning Balance at Dec. 31, 2020	$ 5,662,190	$ 4,935,304	$ 184,299	$ 60,729	$ 45,753	$ (22,507)	$ 458,612
Increase (Decrease) in Stockholders' Equity [Roll Forward]
Net earnings (loss)	185,657				264,859
Net income, non-controlling interests	79,202						(79,202)
Effect of redeemable non-controlling interests not included in equity (note 17)	(4,866)						(4,866)
OCI	(42,550)					(42,799)	249
Dividends declared and distributions to non-controlling interests	(370,140)				(339,531)		(30,609)
Dividends and issuance of shares under dividend reinvestment plan	0	92,495			(92,495)
Contributions received from non-controlling interests, net of cost	1,150,305			6,919		(6,371)	1,149,757
Common shares issued upon conversion of convertible debentures	16	16
Common shares issued upon public offering, net of tax effected cost	988,886	988,886
Common shares issued under employee share purchase plan	5,108	5,108
Share-based compensation	10,036			10,036
Common shares issued pursuant to share-based awards	(9,326)	10,983		(13,437)	(6,872)
Contract adjustment payments (note 7(a))	(222,378)			(62,240)	(160,138)
Non-controlling interest assumed on asset acquisition (note 3(d))	29,141						29,141
Ending Balance at Dec. 31, 2021	7,382,079	6,032,792	184,299	2,007	(288,424)	(71,677)	1,523,082
Increase (Decrease) in Stockholders' Equity [Roll Forward]
Net earnings (loss)	(308,155)				(211,989)
Net income, non-controlling interests	96,166						(96,166)
Effect of redeemable non-controlling interests not included in equity (note 17)	(8,859)						(8,859)
OCI	(90,036)					(88,386)	(1,650)
Dividends declared and distributions to non-controlling interests	(458,028)				(396,965)		(61,063)
Dividends and issuance of shares under dividend reinvestment plan	0	97,801			(97,801)
Contributions received from non-controlling interests, net of cost	273,697						273,697
Common shares issued upon conversion of convertible debentures	6	6
Common shares issued upon public offering, net of tax effected cost	38,227	38,227
Common shares issued under employee share purchase plan	5,319	5,319
Share-based compensation	14,849			14,849
Common shares issued pursuant to share-based awards	(7,711)	9,798		(14,743)	(2,766)
Repurchase of non-controlling interest (note 17)	(4,949)			7,300			(12,249)
Ending Balance at Dec. 31, 2022	$ 6,836,439	$ 6,183,943	$ 184,299	$ 9,413	$ (997,945)	$ (160,063)	$ 1,616,792

Consolidated Statements of Cash Flows - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2022	Dec. 31, 2021
Operating activities
Net earnings (loss)	$ (308,155)	$ 185,657
Adjustments and items not affecting cash:
Depreciation and amortization	455,520	402,963
Deferred taxes	(69,356)	(50,662)
Initial value and unrealized loss (gain) on derivative financial instruments	2,462	(5,609)
Share-based compensation	10,920	8,395
Cost of equity funds used for construction purposes	(1,896)	(637)
Change in value of investments carried at fair value	499,125	122,419
Pension and post-employment expense lower than contributions	(15,329)	(14,146)
Distributions received from equity investments, net of income	23,829	29,818
Impairment of assets	235,478	0
Other	8,116	1,290
Net change in non-cash operating items (note 23)	(221,618)	(522,022)
Net cash provided by (used in) operating activities, total	619,096	157,466
Financing activities
Increase in long-term debt	16,825,796	12,834,047
Repayments of long-term debt	(15,461,078)	(12,895,091)
Issuance of common shares, net of costs	43,546	985,619
Cash dividends on common shares	(378,597)	(307,115)
Dividends on preferred shares	(8,720)	(9,003)
Contributions from non-controlling interests and redeemable non-controlling interests	272,515	1,125,548
Production-based cash contributions from non-controlling interest	6,182	4,832
Distributions to non-controlling interests, related party (note 17)	(34,816)	(28,007)
Distributions to non-controlling interests	(43,919)	(12,830)
Payments upon settlement of derivatives	(28,913)	(33,782)
Shares surrendered to fund withholding taxes on exercised share options	(4,667)	(3,372)
Acquisition of non-controlling interest	(1,580)	0
Increase in other long-term liabilities	19,324	62,000
Decrease in other long-term liabilities	(94,837)	(49,130)
Net cash provided by (used in) financing activities, total	1,110,236	1,673,716
Investing activities
Additions to property, plant and equipment and intangible assets	(1,089,024)	(1,345,045)
Increase in long-term investments	(221,281)	(622,320)
Acquisitions of operating entities (note 3(c))	(632,797)	0
Increase in other assets	(26,527)	(43,306)
Receipt of principal on development loans receivable	178,300	206,319
Decrease in long-term investments	2,920	220
Other proceeds	0	6,023
Net cash provided by (used in) investing activities, total	(1,788,409)	(1,798,109)
Effect of exchange rate differences on cash and restricted cash	(1,127)	(1,702)
Increase (decrease) in cash, cash equivalents and restricted cash	(60,204)	31,371
Cash, cash equivalents and restricted cash, beginning of year	161,389	130,018
Cash, cash equivalents and restricted cash, end of year	101,185	161,389
Supplemental disclosure of cash flow information:
Cash paid during the year for interest expense	272,734	219,025
Cash paid during the year for income taxes	10,962	5,019
Cash received during the year for distributions from equity investments	112,951	112,309
Non-cash financing and investing activities:
Property, plant and equipment acquisitions in accruals	120,819	103,427
Issuance of common shares under dividend reinvestment plan and share-based compensation plans	112,918	108,586
Property, plant and equipment, intangible assets and accrued liabilities in exchange of note receivable	$ 90,700	$ 90,821

Notes to the Consolidated Financial Statements	12 Months Ended
Notes to the Consolidated Financial Statements	Dec. 31, 2022
Organization, Consolidation and Presentation of Financial Statements [Abstract]
Notes to the Consolidated Financial Statements	Algonquin Power & Utilities Corp. (“AQN” or the “Company”) is an incorporated entity under the Canada Business Corporations Act. AQN's operations are organized across two primary business units consisting of the Regulated Services Group and the Renewable Energy Group. The Regulated Services Group owns and operates a portfolio of regulated electric, water distribution and wastewater collection, and natural gas utility systems and transmission operations in the United States, Canada, Bermuda and Chile; the Renewable Energy Group owns and operates, or has investments in, a diversified portfolio of non-regulated renewable and thermal energy generation assets.

Recently issued accounting pronouncements	12 Months Ended
Recently issued accounting pronouncements	Dec. 31, 2022
Accounting Standards Update and Change in Accounting Principle [Abstract]
Recently adopted accounting pronouncements	Recently issued accounting pronouncements (a)Recently adopted accounting pronouncements The Financial Accounting Standards Board (“FASB”) issued ASU 2021-05, Leases (Topic 842): Lessors — Certain Leases with Variable Lease Payments to address concerns relating to day-one losses for sales-type or direct financing leases with variable payments that do not depend on a reference index or rate. The update amends the lease classification requirements for lessors to align them with past practice under Topic 840, Leases. The adoption of this update did not have an impact on the consolidated financial statements. The FASB issued ASU 2020-06, Debt — Debt with Conversion and Other Options (Subtopic 470-20) and Derivatives and Hedging — Contracts in Entity's Own Equity (Subtopic 815-40): Accounting for Convertible Instruments and Contracts in an Entity's Own Equity to address the complexity associated with accounting for certain financial instruments with characteristics of liabilities and equity. The number of accounting models for convertible debt instruments and convertible preferred stock is being reduced and the guidance has been amended for the derivatives scope exception for contracts in an entity's own equity to reduce form-over-substance-based accounting conclusions. The adoption of this update did not have an impact on the consolidated financial statements. The FASB issued ASU 2020-04, Reference Rate Reform (Topic 848): Facilitation of the Effects of Reference Rate Reform on Financial Reporting, which provides optional expedients and exceptions to ease the potential burden in accounting for reference rate reform. The amendments apply to contracts, hedging relationships, and other transactions that reference LIBOR or another reference rate expected to be discontinued because of the reference rate reform. The FASB issued updates to Topic 848 in ASU 2022-06 and 2021-01 to clarify that the scope of Topic 848 includes derivatives affected by the discounting transition and extend the relief in Topic 848 to December 31, 2024, respectively. The adoption of this update did not have an impact on the consolidated financial statements. (b)Recently issued accounting guidance not yet adopted The FASB issued ASU 2022-04, Liabilities — Supplier Finance Programs (Subtopic 405-50): Disclosure of Supplier Finance Program Obligations, which require that a buyer in a supplier finance program disclose sufficient information about the program to allow a user of financial statements to understand the program’s nature, activity during the period, changes from period to period, and potential magnitude. The amendments in this update are effective for fiscal years beginning after December 15, 2022, including interim periods within those fiscal years, except for the amendment on roll forward information, which is effective for fiscal years beginning after December 15, 2023. Early adoption is permitted. The Company is currently assessing the relevant disclosure.

Accounts receivable	12 Months Ended
Accounts receivable	Dec. 31, 2022
Accounts, Notes, Loans and Financing Receivable, Gross, Allowance, and Net [Abstract]
Accounts receivable	Accounts receivableAccounts receivable as of December 31, 2022 include unbilled revenue of $149,015 (December 31, 2021 - $102,693) from the Company’s regulated utilities. Accounts receivable as of December 31, 2022 are presented net of allowance for doubtful accounts of $24,857 (December 31, 2021 - $19,327).

Related party transactions	12 Months Ended
Related party transactions	Dec. 31, 2022
Related Party Transactions [Abstract]
Related party transactions	Related party transactions (a)Equity-method investments The Company provides administrative and development services to its equity-method investees and is reimbursed for incurred costs. To that effect, during 2022, the Company charged its equity-method investees $63,861 (2021 - $25,778). Additionally, Liberty Development JV Inc., an equity-method investee (note 8(c)) provides development services to the Company on specified projects, for which it earns a development fee upon reaching certain milestones. During the year, the development fees charged to the Company were $12,628 (2021 - $2,036). Investment and acquisition transactions with equity-method investments are described in note 8(c). In addition, during 2021, the Company paid $1,500 to Abengoa S.A. (“Abengoa”) to purchase all of Abengoa's interests in the AAGES, AAGES Development Canada Inc., and AAGES Development Spain, S.A. joint ventures. The assets acquired for AAGES Development Spain S.A. included project development assets for $2,662 and working capital of $1,507. The loan at that date between the Company and AAGES Development Spain S.A. of $3,089 was treated as additional consideration paid to acquire the partnership. In 2020, the Company issued a promissory note of $30,493 payable to Altavista Solar Subco, LLC, an equity investee of the Company at the time. The note was repaid in full during the second quarter of 2021. During the fourth quarter of 2021, the Company issued a promissory note of $25,808 payable to New Market Solar Investco, LLC, an equity investee of the Company (note 12(k)). (b)Non-controlling interest and redeemable non-controlling interest held by related party Non-controlling interest and redeemable non-controlling interest held by related party are described in note 17. (c) Transactions with Atlantica During 2021, the Company sold Colombian solar assets to Atlantica for consideration of $23,863, with a gain on sale of $878, and contingent consideration of $2,600. The contingency was resolved in 2022 and, as a result, an additional gain of $1,200 was recognized. The above related party transactions have been recorded at the exchange amounts agreed to by the parties to the transactions.

Comparative figures	12 Months Ended
Comparative figures	Dec. 31, 2022
Organization, Consolidation and Presentation of Financial Statements [Abstract]
Comparative figures	Comparative figuresCertain of the comparative figures have been reclassified to conform to the consolidated financial statement presentation adopted in the current year.

Notes to the Consolidated Financial Statements - Additional Information (Details)	12 Months Ended
	Dec. 31, 2022 business_unit
Organization, Consolidation and Presentation of Financial Statements [Abstract]
Number of business units	2

Significant accounting policies - Additional Information (Detail) $ in Thousands	3 Months Ended	12 Months Ended
	Dec. 31, 2022 USD ($) facility	Dec. 31, 2022 USD ($) facility	Dec. 31, 2021 USD ($)
Significant Accounting Policies [Line Items]
Number of electric generating facilities \| facility	3	3
Cost of plant in service	$ 559,630	$ 559,630	$ 557,954
Liquidity available under the facilities	2,515,600	2,515,600	2,050,200
Accumulated depreciation related to commonly owned facilities	75,820	75,820	59,857
Expenditures		110,268	143,255
U.S. Tax reform		$ 159,568
Number of power generating facilities \| facility		2
Generating assets of Long Sault	17,627,613	$ 17,627,613	16,797,503
Non-regulated energy sales		2,765,155	2,274,142
Interest expense on long-term debt and others		278,574	209,554
Asset impairment charges		(235,478)	0
Non-Regulated Energy
Significant Accounting Policies [Line Items]
Non-regulated energy sales		350,939	256,633
Long Sault and Saint-Damase Wind Powered Generating Facility \| Primary Beneficiary \| Power plant
Significant Accounting Policies [Line Items]
Generating assets of Long Sault	57,241	57,241	59,877
Long-term debt of Long Sault	15,024	15,024	18,344
Operating expenses and amortization		5,834	5,410
Interest expense on long-term debt and others		1,723	2,055
Long Sault and Saint-Damase Wind Powered Generating Facility \| Primary Beneficiary \| Power plant \| Non-Regulated Energy
Significant Accounting Policies [Line Items]
Non-regulated energy sales		$ 19,752	$ 16,772
Renewable Energy Group
Significant Accounting Policies [Line Items]
Asset impairment charges	$ (75,910)
Minimum
Significant Accounting Policies [Line Items]
Ownership interest in commonly owned facilities		7.52%
U.S. Tax reform		$ 100,374
Lease renewal term	1 year	1 year
Minimum \| Renewable Energy Group
Significant Accounting Policies [Line Items]
Asset impairment charges	$ 206,816
Maximum
Significant Accounting Policies [Line Items]
Ownership interest in commonly owned facilities		60.00%
U.S. Tax reform		$ 259,942
Lease renewal term	5 years	5 years
Maximum \| Renewable Energy Group
Significant Accounting Policies [Line Items]
Asset impairment charges	$ 282,726
Power sales contracts \| Minimum
Significant Accounting Policies [Line Items]
Intangible asset, useful life		6 years
Power sales contracts \| Maximum
Significant Accounting Policies [Line Items]
Intangible asset, useful life		25 years
Interconnection agreements
Significant Accounting Policies [Line Items]
Intangible asset, useful life		40 years
Customer relationships \| Minimum
Significant Accounting Policies [Line Items]
Intangible asset, useful life		25 years
Customer relationships \| Maximum
Significant Accounting Policies [Line Items]
Intangible asset, useful life		40 years

Significant accounting policies - Estimated And Weighted Average Useful Lives of Depreciable Assets (Detail)	12 Months Ended
	Dec. 31, 2022	Dec. 31, 2021
Generation \| Weighted Average
Public Utility, Property, Plant and Equipment [Line Items]
Estimated useful lives	33 years	33 years
Generation \| Minimum
Public Utility, Property, Plant and Equipment [Line Items]
Estimated useful lives		3 years
Generation \| Maximum
Public Utility, Property, Plant and Equipment [Line Items]
Estimated useful lives		60 years
Distribution \| Weighted Average
Public Utility, Property, Plant and Equipment [Line Items]
Estimated useful lives	39 years	40 years
Distribution \| Minimum
Public Utility, Property, Plant and Equipment [Line Items]
Estimated useful lives		1 year
Distribution \| Maximum
Public Utility, Property, Plant and Equipment [Line Items]
Estimated useful lives		100 years
Equipment \| Weighted Average
Public Utility, Property, Plant and Equipment [Line Items]
Estimated useful lives	11 years	11 years
Equipment \| Minimum
Public Utility, Property, Plant and Equipment [Line Items]
Estimated useful lives	5 years	5 years
Equipment \| Maximum
Public Utility, Property, Plant and Equipment [Line Items]
Estimated useful lives	54 years	50 years

Business acquisitions, development projects and disposition transactions - Additional Information (Details) $ in Thousands, $ in Thousands					1 Months Ended		12 Months Ended
	Dec. 29, 2022 CAD ($) business_unit	Sep. 29, 2022 USD ($)	Jan. 01, 2022 USD ($) country	Oct. 26, 2021 USD ($)	Apr. 30, 2021 USD ($) MWac	Jan. 31, 2021 USD ($) MWac wind_project	Dec. 31, 2022 USD ($) county	Dec. 31, 2021 USD ($) MWac wind_project	Dec. 31, 2019 MWac	Dec. 29, 2022 USD ($)	Dec. 29, 2022 CAD ($)	Mar. 31, 2022 USD ($)
Business Acquisition [Line Items]
Gain on sale of renewable assets							$ 64,028	$ 29,063
Number of counties served \| county							20
Business combination, consideration transferred, liabilities incurred						$ 87,035
Operating Wind Facilities in the United States
Business Acquisition [Line Items]
Equity interest (percent)										49.00%	49.00%
Number of ownership interest \| business_unit	3
Wind power capacity (megawatt AC) \| MWac									551
Altavista Solar Facility
Business Acquisition [Line Items]
Equity interest (percent)					50.00%
Blue Hill Wind Facility
Business Acquisition [Line Items]
Equity interest (percent)										80.00%	80.00%
Wind power capacity (megawatt AC) \| MWac									175
Proceeds from sale of renewable assets										$ 277,500	$ 108,610
Gain on sale of renewable assets	$ 62,828
Kentucky Power Transaction
Business Acquisition [Line Items]
Total purchase price				$ 2,846,000
Reduction to the purchase price		$ 200,000
AEP Kentucky Transmission Company, Inc
Business Acquisition [Line Items]
Debt assumed				$ 1,221,000
New York Water Company, Inc
Business Acquisition [Line Items]
Total purchase price			$ 609,000
Number of countries \| country			8
Intangible asset, useful life			64 years 8 months 26 days
Revenue							$ 125,370
Operating income							$ 21,776
Mid-West Wind Facilities
Business Acquisition [Line Items]
Debt assumed								$ 789,804
Mid-West Wind Facilities \| Empire Electric System
Business Acquisition [Line Items]
Wind power capacity (megawatt AC) \| MWac								600
Total purchase price								$ 97,760
Tax equity funding								530,880
Debt repaid upon maturity								$ 789,923
Number of wind projects \| wind_project								3
Maverick Creek and Sugar Creek Wind Facilities
Business Acquisition [Line Items]
Debt assumed						855,409
Total purchase price						$ 18,641
Number of wind projects \| wind_project						2
Ownership interest acquired (percent)						50.00%
Investments in joint venture												$ 43,797
Altavista Solar Facility
Business Acquisition [Line Items]
Debt assumed					$ 122,024
Total purchase price					$ 6,735
Solar power capacity (megawatt ac) \| MWac					80
Maverick Creek Wind Facility
Business Acquisition [Line Items]
Wind power capacity (megawatt AC) \| MWac						492
Tax equity funding						$ 380,829
Debt repaid upon maturity						$ 570,578
Sugar Creek Wind Facility
Business Acquisition [Line Items]
Wind power capacity (megawatt AC) \| MWac						202
Tax equity funding						$ 147,914
Debt repaid upon maturity						$ 284,829

Business acquisitions, development projects and disposition transactions - Schedule of Preliminary Allocation Of The Acquisition Prices Of Assets Acquired and Liabilities Assumed (Details) - USD ($) $ in Thousands	Dec. 31, 2022	Jan. 01, 2022	Dec. 31, 2021	Apr. 30, 2021	Jan. 31, 2021	Dec. 31, 2020
Business Acquisition [Line Items]
Goodwill (note 6)	$ 1,320,579		$ 1,201,244			$ 1,208,390
New York Water Company, Inc
Business Acquisition [Line Items]
Working capital		$ 4,820
Property, plant and equipment		499,252
Goodwill (note 6)		116,254
Regulatory assets		65,621
Other assets		4,507
Pension and other post-employment benefits		(13,402)
Regulatory liabilities		(59,727)
Other liabilities		(8,028)
Total net assets acquired		609,297
Cash and cash equivalents		49
Net assets acquired, net of cash and cash equivalents		$ 609,248
Mid-West Wind Facilities
Business Acquisition [Line Items]
Working capital			(28,630)
Property, plant and equipment			1,141,884
Long-term debt			(789,804)
Deferred tax liability			(4,566)
Asset retirement obligation			(27,053)
Other liabilities			(104,129)
Non-controlling interest (tax equity investors)			(29,141)
Total net assets acquired			158,561
Cash and cash equivalents			15,860
Net assets acquired, net of cash and cash equivalents			$ 142,701
Altavista Solar Facility
Business Acquisition [Line Items]
Working capital				$ 870
Property, plant and equipment				138,343
Long-term debt				(122,024)
Deferred tax liability				(421)
Asset retirement obligation				(3,332)
Total net assets acquired				13,436
Cash and cash equivalents				33
Net assets acquired, net of cash and cash equivalents				$ 13,403
Maverick Creek and Sugar Creek Wind Facilities
Business Acquisition [Line Items]
Working capital					$ (15,557)
Property, plant and equipment					1,062,613
Long-term debt					(855,409)
Deferred tax liability					(337)
Asset retirement obligation					(23,402)
Derivative instruments					7,575
Total net assets acquired					175,483
Cash and cash equivalents					4,241
Net assets acquired, net of cash and cash equivalents					$ 171,242

Accounts receivable - Additional Information (Detail) - USD ($) $ in Thousands	Dec. 31, 2022	Dec. 31, 2021
Accounts, Notes, Loans and Financing Receivable [Line Items]
Allowance for doubtful accounts receivable	$ 24,857	$ 19,327
Unbilled revenue
Accounts, Notes, Loans and Financing Receivable [Line Items]
Accounts receivable balances	$ 149,015	$ 102,693

Property, plant and equipment - Schedule of Plant, Property and Equipment (Detail) - USD ($) $ in Thousands	Dec. 31, 2022	Dec. 31, 2021
Property, Plant and Equipment [Line Items]
Cost	$ 14,003,548	$ 12,630,666
Accumulated depreciation	2,058,663	1,588,220
Net book value	11,944,885	11,042,446
Land
Property, Plant and Equipment [Line Items]
Cost	113,153	114,821
Accumulated depreciation	0	0
Net book value	113,153	114,821
Equipment
Property, Plant and Equipment [Line Items]
Cost	111,707	101,971
Accumulated depreciation	50,904	56,464
Net book value	60,803	45,507
Generation
Property, Plant and Equipment [Line Items]
Cost	4,119,514	4,187,197
Accumulated depreciation	1,016,784	751,219
Net book value	3,102,730	3,435,978
Generation \| Construction in progress
Property, Plant and Equipment [Line Items]
Cost	196,287	148,302
Accumulated depreciation	0	0
Net book value	196,287	148,302
Utility plant
Property, Plant and Equipment [Line Items]
Cost	8,640,224	7,468,236
Accumulated depreciation	990,975	780,537
Net book value	7,649,249	6,687,699
Distribution and transmission \| Construction in progress
Property, Plant and Equipment [Line Items]
Cost	822,663	610,139
Accumulated depreciation	0	0
Net book value	$ 822,663	$ 610,139

Property, plant and equipment - Additional Information (Detail) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2022	Dec. 31, 2021
Property, Plant, and Equipment Disclosure [Line Items]
Cost of plant in service	$ 559,630	$ 557,954
Accumulated depreciation related to commonly owned facilities	75,820	59,857
Expenditures	110,268	143,255
Contribution received	1,299	6,376
Generation
Property, Plant, and Equipment Disclosure [Line Items]
Renewable generation assets related to facilities under capital lease and owned by consolidated VIE	111,192	114,868
Renewable generation assets related to facilities under capital lease and owned by consolidated VIE, accumulated depreciation	46,666	46,649
Depreciation expense	1,489	1,716
Regulated Services Group
Property, Plant, and Equipment Disclosure [Line Items]
Cost of distribution assets	3,076	3,076
Accumulated depreciation	2,041	1,665
Utility plant
Property, Plant, and Equipment Disclosure [Line Items]
Renewable generation assets related to facilities under capital lease and owned by consolidated VIE	2,033,391	2,018,039
Renewable generation assets related to facilities under capital lease and owned by consolidated VIE, accumulated depreciation	$ 133,644	$ 72,484

Property, plant and equipment - Interest and AFUDC Capitalized (Details) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2022	Dec. 31, 2021
Schedule of Capitalization [Line Items]
Total	$ 12,703	$ 7,350
Non-regulated property
Schedule of Capitalization [Line Items]
Interest capitalized on non-regulated property	4,762	3,313
Interest expense
Schedule of Capitalization [Line Items]
AFUDC capitalized on regulated property:	6,040	3,208
Interest, dividend and other income
Schedule of Capitalization [Line Items]
AFUDC capitalized on regulated property:	$ 1,901	$ 829

Intangible assets and goodwill - Schedule of Intangible Assets (Details) - USD ($) $ in Thousands	Dec. 31, 2022	Dec. 31, 2021
Finite-Lived Intangible Assets [Line Items]
Cost	$ 155,212	$ 162,292
Accumulated amortization	58,529	57,176
Net book value	96,683	105,116
Power sales contracts
Finite-Lived Intangible Assets [Line Items]
Cost	56,926	58,112
Accumulated amortization	42,818	43,118
Net book value	14,108	14,994
Customer relationships
Finite-Lived Intangible Assets [Line Items]
Cost	77,850	78,140
Accumulated amortization	13,709	12,337
Net book value	64,141	65,803
Interconnection agreements
Finite-Lived Intangible Assets [Line Items]
Cost	10,098	15,072
Accumulated amortization	1,851	1,721
Net book value	8,247	13,351
Other
Finite-Lived Intangible Assets [Line Items]
Cost	10,338	10,968
Accumulated amortization	151	0
Net book value	$ 10,187	$ 10,968

Intangible assets and goodwill - Additional Information (Details) $ in Thousands	Dec. 31, 2022 USD ($)
Finite-Lived Intangible Assets, Net, Amortization Expense, Fiscal Year Maturity [Abstract]
Estimated amortization expense for intangibles in year 1	$ 2,580
Estimated amortization expense for intangibles in year 2	2,572
Estimated amortization expense for intangibles in year 3	2,572
Estimated amortization expense for intangibles in year 4	2,572
Estimated amortization expense for intangibles in year 5	$ 2,572

Intangible assets and goodwill - Schedule of Goodwill (Details) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2022	Dec. 31, 2021
Goodwill [Roll Forward]
Goodwill beginning of the period	$ 1,201,244	$ 1,208,390
Business acquisitions (note 3)	123,751	5,535
Foreign exchange	(4,416)	(12,681)
Goodwill end of the period	$ 1,320,579	$ 1,201,244

Regulatory Matters - Regulatory Proceedings (Details) - USD ($) $ in Thousands							1 Months Ended
	Feb. 03, 2023	Dec. 29, 2022	Dec. 22, 2022	Mar. 18, 2022	Jan. 19, 2022	Nov. 22, 2021	Jun. 30, 2022	May 31, 2022	Jan. 31, 2022
BELCO
Regulatory Liabilities [Line Items]
Revenue allowance, 2022				$ 224,056
Approved revenue increase (decrease)				22,800
Revenue allowance, 2023				$ 226,160
Weighted average cost of capital (percent)				7.16%
Approved equity capital structure, (percent)				62.00%
Approved return on equity, (percent)				8.92%
Empire Electric System - Missouri
Regulatory Liabilities [Line Items]
First requested increase					$ 35,516
Second requested increase					4,000
Qualified extraordinary costs					$ 290,383
Empire Electric System - Kansas
Regulatory Liabilities [Line Items]
Requested increase								$ 636
Empire District Gas Company
Regulatory Liabilities [Line Items]
Requested increase							$ 1,000
Empire Electric - Oklahoma
Regulatory Liabilities [Line Items]
Requested increase		$ 5,100
New Brunswick Gas - Canada
Regulatory Liabilities [Line Items]
Approved equity capital structure, (percent)						45.00%
Approved return on equity, (percent)			9.80%			8.50%
Annual revenue increase (decrease)			$ 1,265						$ 1,041
Apple Valley Ranchos Water System \| Subsequent Event
Regulatory Liabilities [Line Items]
Annual revenue increase (decrease)	$ (1,412)
Park Water System \| Subsequent Event
Regulatory Liabilities [Line Items]
Annual revenue increase (decrease)	$ 1,105

Regulatory matters - Regulatory Assets and Liabilities (Detail) $ in Thousands	1 Months Ended	12 Months Ended
	Sep. 22, 2022 USD ($)	Dec. 31, 2022 USD ($)	Apr. 27, 2022 regulatory_case	Dec. 31, 2021 USD ($)	Mar. 01, 2020 MWac
Regulatory Liabilities [Line Items]
Total regulatory assets		$ 1,271,501		$ 1,167,625
Less: current regulatory assets		(190,393)		(158,212)
Non-current regulatory assets		1,081,108		1,009,413
Total regulatory liabilities		628,182		576,189
Less: current regulatory liabilities		(69,865)		(65,809)
Non-current regulatory liabilities		$ 558,317		510,380
Capital expenditure shortfall refundable to customers (percent)		80.00%
Retroactive rate adjustment collection period		24 months
Regulatory asset, amortization period		26 years
Income taxes
Regulatory Liabilities [Line Items]
Total regulatory liabilities		$ 312,671		295,720
Cost of removal
Regulatory Liabilities [Line Items]
Total regulatory liabilities		191,173		191,981
Pension and post-employment benefits
Regulatory Liabilities [Line Items]
Total regulatory liabilities		68,085		34,468
Fuel and commodity costs adjustments
Regulatory Liabilities [Line Items]
Total regulatory liabilities		24,991		18,175
Clean energy and other customer programs
Regulatory Liabilities [Line Items]
Total regulatory liabilities		11,572		14,829
Rate adjustment mechanism
Regulatory Liabilities [Line Items]
Total regulatory liabilities		$ 343		3,316
Rate adjustment mechanism \| Minimum
Regulatory Liabilities [Line Items]
Regulatory assets, recovery period		1 year
Rate adjustment mechanism \| Maximum
Regulatory Liabilities [Line Items]
Regulatory assets, recovery period		5 years
Other
Regulatory Liabilities [Line Items]
Total regulatory liabilities		$ 19,347		17,700
Fuel and commodity costs adjustments
Regulatory Liabilities [Line Items]
Total regulatory assets		388,294		339,900
Asset Retirement Obligation		21,283
Number of regulatory cases \| regulatory_case			2
Qualified extraordinary costs	$ 290,383
Recovery denied (percent)	5.00%
Fuel and commodity costs adjustments \| Midwest Extreme Weather Event
Regulatory Liabilities [Line Items]
Issuance of securitized tariff bonds, authorized amount		221,646
Fuel and commodity costs adjustments \| Energy Transistion Costs
Regulatory Liabilities [Line Items]
Issuance of securitized tariff bonds, authorized amount		140,774
Retired generating plant
Regulatory Liabilities [Line Items]
Total regulatory assets		174,609		185,073
Coal generation capacity (MW) \| MWac					200
Pension and post-employment benefits
Regulatory Liabilities [Line Items]
Total regulatory assets		$ 80,736		134,287
Future service years of employees		10 years
Rate adjustment mechanism
Regulatory Liabilities [Line Items]
Total regulatory assets		$ 136,198		117,309
Environmental remediation
Regulatory Liabilities [Line Items]
Total regulatory assets		$ 70,529		81,802
Environmental remediation, rate recovery period		7 years
Income taxes
Regulatory Liabilities [Line Items]
Total regulatory assets		$ 97,414		79,472
Deferred capitalized costs
Regulatory Liabilities [Line Items]
Total regulatory assets		$ 90,121		62,599
Regulatory asset, amortization period		20 years
Capitalized operating and maintenance costs, recovery rate, (percent)		2.43%
Wildfire mitigation and vegetation management
Regulatory Liabilities [Line Items]
Total regulatory assets		$ 66,156		35,726
Regulatory assets, recovery period		2 years
Debt premium
Regulatory Liabilities [Line Items]
Total regulatory assets		$ 24,888		34,204
Cost of removal
Regulatory Liabilities [Line Items]
Total regulatory assets		11,084		0
Asset retirement obligation
Regulatory Liabilities [Line Items]
Total regulatory assets		27,172		26,810
Clean energy and other customer programs
Regulatory Liabilities [Line Items]
Total regulatory assets		$ 28,145		25,857
Clean energy and other customer programs \| Minimum
Regulatory Liabilities [Line Items]
Regulatory assets, recovery period		6 years
Clean energy and other customer programs \| Maximum
Regulatory Liabilities [Line Items]
Regulatory assets, recovery period		10 years
Rate review costs
Regulatory Liabilities [Line Items]
Total regulatory assets		$ 9,481		9,167
Rate review costs \| Minimum
Regulatory Liabilities [Line Items]
Costs capitalized and amortized period		1 year
Rate review costs \| Maximum
Regulatory Liabilities [Line Items]
Costs capitalized and amortized period		5 years
Long-term maintenance contract
Regulatory Liabilities [Line Items]
Total regulatory assets		$ 6,504		9,134
Regulatory assets, recovery period		5 years
Other
Regulatory Liabilities [Line Items]
Total regulatory assets		$ 60,170		$ 26,285

Long-term investments - Schedule of Long-Term Investments (Detail) - USD ($) $ in Thousands	Dec. 31, 2022	Dec. 31, 2021
Schedule of Equity Method Investments [Line Items]
Investments carried at fair value	$ 1,344,207	$ 1,848,456
Equity-method investees	381,802	433,850
Other	27,600	30,508
Long-term investments	462,325	495,826
Notes Receivable \| Development loans
Schedule of Equity Method Investments [Line Items]
Development loans receivable from equity-method investees	52,923	31,468
Atlantica
Schedule of Equity Method Investments [Line Items]
Investments carried at fair value	1,268,140	1,750,914
Atlantica Yield Energy Solutions Canada Inc.
Schedule of Equity Method Investments [Line Items]
Investments carried at fair value	74,083	95,246
Other
Schedule of Equity Method Investments [Line Items]
Investments carried at fair value	$ 1,984	$ 2,296

Long-term investments - Additional Information (Detail) $ in Thousands	1 Months Ended	3 Months Ended	12 Months Ended
	May 31, 2020 shares	Mar. 31, 2021 wind_project	Dec. 31, 2022 USD ($)	Dec. 31, 2021 USD ($)	Dec. 29, 2022	Nov. 30, 2021 USD ($)	Dec. 31, 2020 USD ($)
Schedule of Equity Method Investments [Line Items]
AQN's investment carrying amount for the entities			$ 381,802	$ 433,850
Investments carried at fair value			1,344,207	1,848,456
Noncontrolling interest in partnerships and joint ventures			381,802	433,850
Number of wind development projects \| wind_project		4
Guarantor obligations			113,630	119,750
Fair value of support provided			8,824	4,612
Net loss attributable to AQN			(21,416)	(26,337)
Variable Interest Entity, Not Primary Beneficiary
Schedule of Equity Method Investments [Line Items]
Net assets			$ 122,752	$ 86,202
Atlantica
Schedule of Equity Method Investments [Line Items]
Equity interest (percent)			42.00%	44.00%
Equity interest, maximum (percent)			48.50%
AQN's investment carrying amount for the entities			$ 1,167,444	$ 1,167,444
Investments carried at fair value			$ 1,268,140	1,750,914
Atlantica Yield Energy Solutions Canada Inc.
Schedule of Equity Method Investments [Line Items]
Option to exchange shares \| shares	3,500,000
Common stock, conversion ratio			1
Investments carried at fair value			$ 74,083	95,246
Texas Coastal Wind Facilities
Schedule of Equity Method Investments [Line Items]
AQN's investment carrying amount for the entities				344,883
Equity method investment acquired (percent)		51.00%	51.00%
Texas Coastal Wind Facilities \| Maximum
Schedule of Equity Method Investments [Line Items]
AQN's investment carrying amount for the entities			$ 282,726
Texas Coastal Wind Facilities \| Minimum
Schedule of Equity Method Investments [Line Items]
AQN's investment carrying amount for the entities				206,816
Liberty Development JV Inc
Schedule of Equity Method Investments [Line Items]
AQN's investment carrying amount for the entities						$ 19,688
Equity method investment, gain on transfer			$ 0	26,182
Wind And Solar Power Electric Development
Schedule of Equity Method Investments [Line Items]
Equity interest (percent)			50.00%
San Antonio Water System
Schedule of Equity Method Investments [Line Items]
Equity interest (percent)			20.00%
Blue Hill Wind Facility
Schedule of Equity Method Investments [Line Items]
Equity interest (percent)					80.00%
Equity method investment acquired (percent)			20.00%
Investments in Significant Partnerships and Joint Ventures
Schedule of Equity Method Investments [Line Items]
AQN's investment carrying amount for the entities			$ 381,802	433,850			$ 186,452
Net loss attributable to AQN			$ (21,416)	$ (26,337)

Long-term investments - Operating entities (Detail) - $ / MWh	3 Months Ended	12 Months Ended
	Mar. 31, 2021	Dec. 31, 2022
Texas Coastal Wind Facilities
Schedule of Equity Method Investments [Line Items]
Equity method investment acquired (percent)	51.00%	51.00%
Wind facility capacity (megawatt AC)		861,000
Blue Hill Wind Facility
Schedule of Equity Method Investments [Line Items]
Equity method investment acquired (percent)		20.00%
Wind facility capacity (megawatt AC)		175,000
Red Lily Wind Facility
Schedule of Equity Method Investments [Line Items]
Equity method investment acquired (percent)		75.00%
Wind facility capacity (megawatt AC)		26,400
Val-Eo Wind Facility
Schedule of Equity Method Investments [Line Items]
Equity method investment acquired (percent)		50.00%
Wind facility capacity (megawatt AC)		24,000

Long-term investments - Equity method investees (Detail) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2022	Dec. 31, 2021
Equity Method Investment [Roll Forward]
Carrying value, January 1	$ 433,850
Net loss attributable to AQN	(21,416)	$ (26,337)
Operating projects bought back by AQN	0	(129,075)
Dividend received	(23,829)	(29,818)
Impairment		0
Reclassification during the period (note 8(e))	0	(25,634)
Carrying value, December 31	381,802	433,850
Investments in Significant Partnerships and Joint Ventures
Equity Method Investment [Roll Forward]
Carrying value, January 1	433,850	186,452
Additional Investments	110,441	418,434
Net loss attributable to AQN	(21,416)	(26,337)
Other comprehensive loss attributable to AQN	(67,110)	7,733
Dividend received	(1,183)	(2,981)
Other	3,130	5,258
Carrying value, December 31	$ 381,802	$ 433,850