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 16, 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.

1See 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 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, 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 ConcerningForward-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 ConcerningNon-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 endedDecember 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	Various	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 1,853.7GW-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 6,823.0GW-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 Note21 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 endedDecember 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 endedDecember 31, 2022, the Renewable Energy Group's facilities generated $472.2 million of Divisional Operating Profitas 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.

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:

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 endedDecember 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 endedDecember 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 endedDecember 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 endedDecember 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 endedDecember 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 investees2 $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).

2Primarily Liberty Development JV Inc. and its subsidiaries, Blue Hill Wind Energy Project Partnership, and Red Lily Wind Energy Partnership.

Algonquin Power & Utilities Corp. - Management Discussion & Analysis 46

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.

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 Risk Committee of the Board periodically.

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.

•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 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.

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.

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.

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;

•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 Company;

•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

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.

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

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

Algonquin Power & Utilities Corp. - Management Discussion & Analysis 61

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.

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 Company in unpredictable ways, including

Algonquin Power & Utilities Corp. - Management Discussion & Analysis 62

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.

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 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.

Algonquin Power & Utilities Corp. - Management Discussion & Analysis 64

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

Algonquin Power & Utilities Corp. - Management Discussion & Analysis 65

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

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 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.

Algonquin Power & Utilities Corp. - Management Discussion & Analysis 66

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

Algonquin Power & Utilities Corp. - Management Discussion & Analysis 67

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