Exhibit 99.1

 Algonquin Power & Utilities Corp.  2023 Annual Report 

 Inside front cover  Forward-looking information  This document contains statements that constitute “forward-looking statements” or “forward- looking information” within the meaning of applicable securities legislation (collectively, “forward- looking information”). The words “aims”, “anticipates”, “expects”, “could”, “intends”, “may”, “plans”, “potential”, “will”, “would”, “seeks”, “target”, “trends” and similar words and 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: the sale of the renewable energy business, including the timing and completion thereof, resulting long-term valuation creation, impacts on the Regulated Services Group, common share dividend, cost of capital and credit rating; Algonquin Power & Utilities Corp. becoming a pure-play regulated utility, simplifying the business and achieving greater operational efficiency; the search for a permanent Chief Executive Officer;  near-term priorities for 2024; expected future growth, earnings, and operations; and services provided to customers. Readers are advised that all forward-looking information in this document is provided subject to the ”Caution Concerning Forward-Looking Statements and Forward-Looking Information” section of the Management Discussion & Analysis section of this Annual Report.  Corporate profile  III  Letter from the Interim Chief Executive Officer  V  Regulated Services Group  VI  Renewable Energy Group  VII  2023 stats at a glance  VIII  Financial highlights  IX  Total assets  X  1  69  70  71  82  Appendices  Management Discussion & Analysis Consolidated Financial Statements  Management’s Report Independent Auditor’s Report  Notes to the Consolidated Financial Statements  Algonquin’s leadership  145  Corporate info  B  ALGONQUIN | LIBERTY  II  2023 Annual Report 

 Algonquin Power & Utilities Corp. (“Algonquin”, “we”, or “our”), parent company of Liberty, is a diversified international generation, transmission, and distribution utility with approximately $18 billion of total assets. Algonquin is committed to providing safe, secure, reliable, cost-effective, and sustainable energy and water solutions through its portfolio of generation, transmission, and distribution utility investments to over one million customer connections, largely in the United States and Canada. In addition, Algonquin owns, operates, and/or has net interests in over 4 GW of installed renewable energy capacity.  AlgonquinPower.com TSX/NYSE: AQN  1. Data in this report is provided as of December 31, 2023, unless otherwise stated. Dollar figures herein are presented in U.S. dollars unless otherwise stated.  III 

 ALGONQUIN | LIBERTY  2IV  2023 Annual Report 

 Dear fellow shareholder,  2023 was a decisive year for Algonquin. We made several strategic decisions, and are now focused on becoming a pure-play regulated utility, simplifying the business, and achieving greater operational efficiency.  In August 2023, following a thorough strategic review, Algonquin announced that it would be pursuing a sale of its renewable energy business. The Strategic Review Committee of the Board carefully evaluated both the Regulated Services Group and Renewable Energy Group and determined that long-term value creation would be better realized by separating and selling our renewable energy business. We are excited about the opportunities  ahead, which we expect will shape our Regulated Services Group into a leading utility platform while supporting  our current common share dividend, reducing our cost of capital, and maintaining our BBB investment grade credit rating—all with the objective to build long-term value for shareholders.  When I took on the position of Interim Chief Executive Officer in August 2023, I was focused on four priorities: our people, the sale of our renewable energy business, optimizing the value of our investment in Atlantica Sustainable Infrastructure plc, and getting the Regulated Services Group established as a standalone business.  Although there is still work to be done, we are making progress.  From a 2023 business segment performance standpoint, new rate implementations across our utility portfolio contributed to financial growth for our Regulated Services Group, and our Renewable Energy Group placed in service over 450 MW of new wind and solar generation. These results demonstrate that, despite 2023 headwinds and the strategic transition currently underway, we have two solid businesses.  The sale process for our renewable energy business is proceeding as planned and we continue to target  completion at or around the end of 2024. We launched the sale process with potential buyers in the fourth quarter of 2023 and are pleased with the level of buyer interest.  We also continue our search for a permanent Chief Executive Officer and have been pleased with the slate of candidates reviewed thus far. In the meantime, I remain dedicated to the role of Interim CEO, with the focus being on the following near-term priorities for 2024:  1. Growing our people and their capabilities  2. Executing on the sale of our renewable energy business  3. Meeting our financial objectives  4. Optimizing the Regulated Services Group as a standalone business  In short, we are centering our efforts this year on  the initiatives that are essential to our ability to move Algonquin forward.  Finally, we want to offer our heartfelt thanks to our key stakeholders for your support and patience as we navigated through a challenging yet transformative  year. Our sincere gratitude goes to our dedicated team of employees for their ongoing pursuit of operational excellence, to our Board of Directors for their counsel, and to our valued investors for their ongoing trust in us.  Yours Sincerely,  Chris Huskilson,  Interim Chief Executive Officer  V 

 The Regulated Services Group primarily operates a diversified portfolio of regulated utility systems located in the United States, Canada, Bermuda, and Chile serving approximately 1,256,000 customer connections. The Regulated Services Group seeks to provide safe, high-quality, and reliable services to its customers and to deliver stable and predictable earnings to Algonquin.  In addition to encouraging and supporting organic growth within its service territories, the Regulated Services Group may seek to deliver long-term growth through acquisitions of additional utility systems and pursuing “greening the fleet” opportunities.  ~1,256,000  connections  $7.2 billion  in rate base1  13 U.S. states,  1 Canadian province, Bermuda, and Chile  ~$12.7 billion regulated utility assets  1. Rate base is a measure specific to rate-regulated utilities that is not intended to represent any financial measure as defined by United States generally accepted accounting principles ("U.S. GAAP"). The measure is used by the regulatory authorities in the jurisdictions in which Algonquin’s rate-regulated subsidiaries operate. The calculation of this measure may not be comparable to similarly titled measures used by other companies.  VI ALGONQUIN | LIBERTY  2023 Annual Report 

 5  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 located in 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 has economic interests in hydroelectric, wind, solar, renewable natural gas, and thermal facilities with a combined net generating capacity attributable to the Renewable Energy  Group of approximately 2.7 GW. Approximately 84% of the electrical output is sold pursuant to long-term contractual arrangements which have a production-weighted average remaining contract life of approximately 10 years.  In addition, the Renewable Energy Group has an approximately 42% indirect beneficial interest in Atlantica Sustainable Infrastructure plc.  46  renewable and clean energy facilities  ~2.7 GW  net economic ownership  ~8 GW  development pipeline  ~$5.4 billion1  non-regulated power generation assets  1. Includes a proportionate amount based on Algonquin’s ~42% equity interest in Atlantica Sustainable Infrastructure plc’s wind and solar assets as of December 31, 2023.  VII 

 Over $18 billion  total assets  ~$4.36 billion  market cap (NYSE)  8,482 miles  of gas distribution lines  13,517 miles  of electricity distribution lines  6,941 miles  of water distribution mains  ~309,000  electric customer connections  ~375,000  natural gas customer connections  ~572,000  water and wastewater customer connections  1,320  wind turbines  1,516,685  solar panels  54  hydroelectric generators  3,900+  employees  Founded in  1988  Headquartered in Greater Toronto Area, Ontario  VIII ALGONQUIN | LIBERTY  2023 Annual Report 

 1. The terms “Adjusted EBITDA”, “Adjusted Net Earnings”, “Adjusted Net Earnings per common share” and “Adjusted Funds from Operations” (together, the “Non-GAAP Measures”) are used herein. The Non-GAAP Measures are not recognized measures under U.S. GAAP. There is no standardized measure of the Non-GAAP Measures. Consequently, Algonquin’s method of calculating the Non-GAAP Measures may differ from methods used by other companies and therefore may not be comparable to similar measures presented by other companies. An explanation and analysis of the Non-GAAP Measures and a reconciliation to the most comparable  U.S. GAAP measure can be found in the Management Discussion & Analysis section of this Annual Report under the headings “Caution Concerning Non-GAAP Measures” and “Non-GAAP Financial Measures”.  2. Includes current portion of long-term debt, long-term debt, and convertible debentures.  Financial highlights  Twelve months ended December 31  (in USD millions except per share information)  2023  2022  2021  Revenue  Renewable Energy Group  329.7  379.2  275.0  Regulated Services Group  2,366.9  2,384.3  1,997.6  Corporate  1.4  1.5  1.6  Total Revenue  2,698.0  2,765.0  2,274.1  Net earnings (loss) attributable to shareholders  28.7  (212.0)  264.9  Adjusted EBITDA1  1,235.4  1,192.8  1,076.3  Earnings, Funds from Operations, and Dividends  Cash provided by operating activities  628.0  619.1  157.5  Adjusted Funds from Operations1  724.6  790.3  757.9  Adjusted Net Earnings1  372.0  420.3  449.0  Per common share1  0.53  0.61  0.71  Dividends declared to common shareholders  301.8  486.0  423.0  Per share  0.43  0.71  0.67  Balance Sheet Data  Total Assets  18,374.0  17,627.6  16,797.5  Long Term Debt2  8,516.0  7,512.3  6,211.7  Weighted average number of common shares outstanding  688,738,717  677,862,207  622,347,677  Renewable energy production (% of long term average)  84%  94%  90%  Utility Connections  1,256,000  1,250,000  1,093,000  Adjusted EBITDA1  $1,235.4 million  3.6%  Adjusted Net Earnings1  $372.0 million  11.5%  Total Revenue  $2,698.0 million  2.4%  IX 

 8  $10,920.8  $13,224.1  $16,797.5  $17,627.6  $18,374.0  2019  2020  2021  2022  2023  5-year CAGR: 14.3%  Total assets  (in USD millions)  X ALGONQUIN | LIBERTY  2023 Annual Report 

Management Discussion & Analysis

Management of Algonquin Power & Utilities Corp. (“AQN”, “Company” or the “Corporation”) has prepared the following discussion and analysis to provide information to assist its securityholders’ understanding of the financial results for the three and twelve months ended December 31, 2023. This Management Discussion & Analysis (“MD&A”) should be read in conjunction with AQN’s annual consolidated financial statements for the years ended December 31, 2023 and 2022. This material is available on SEDAR+ at www.sedarplus.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.sedarplus.com and on EDGAR at www.sec.gov/edgar.

Contents

Explanatory Notes	2
Caution Concerning Forward-Looking Statements and Forward-Looking Information	3
Caution Concerning Non-GAAP Measures	5
Overview and Business Strategy	7
Significant Updates	10
2023 Fourth Quarter Results From Operations	12
2023 Annual Results from Operations	15
2023 Net Earnings Summary	18
2023 Adjusted EBITDA Summary	19
Regulated Services Group	20
Renewable Energy Group	30
AQN: Corporate and Other Expenses	36
Non-GAAP Financial Measures	38
Summary of Property, Plant and Equipment Expenditures	40
Liquidity and Capital Reserves	42
Share-Based Compensation Plans	46
Management of Capital Structure	47
Related Party Transactions	48
Enterprise Risk Management	49
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

Explanatory Notes

Unless otherwise indicated, financial information provided for the years ended December 31, 2023 and 2022 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. Certain amounts in this MD&A may not total due to rounding.

Capitalized terms used herein and not otherwise defined have the meanings assigned to them in the Company's most recent AIF.

The term “rate base” is used in this document. Rate base is a measure specific to rate-regulated utilities that is not intended to represent any financial measure as defined by U.S. GAAP. The measure is used by the regulatory authorities in the jurisdictions where the Company’s rate-regulated subsidiaries operate. The calculation of this measure may not be comparable to similarly-titled measures used by other companies.

Unless noted otherwise, this MD&A is based on information available to management as of March 8, 2024.

Algonquin Power & Utilities Corp. - Management Discussion & Analysis 2

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 and results of operations; the sale of the Corporation's renewable energy business and the anticipated impact thereof on the Corporation; 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 or asset sales initiatives; ongoing and planned acquisitions, dispositions, projects, initiatives or other transactions, including expectations regarding timing, costs, proceeds, financing, results, ownership structures, regulatory matters, in-service dates and completion dates; financing plans; expectations regarding future macroeconomic conditions; expectations regarding the Company's corporate development activities and the results thereof; expectations regarding regulatory hearings, motions, filings, appeals and approvals, including rate reviews, and the timing, impacts and outcomes thereof; expectations regarding the exercise of the Company's purchase option in respect of the remaining 50% interests in the Sandy Ridge II and Shady Oaks II Wind Facilities; expectations regarding the redemption of outstanding notes; 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; capital management plans and objectives; 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; credit ratings and equity credit from rating agencies, including expectations regarding the resolution of rating watches related to the intended sale of the Corporation’s renewable energy business; 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 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; 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; 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 absence of undisclosed liabilities of entities being acquired; that such entities will maintain constructive regulatory relationships with applicable 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; and the ability of the Corporation to successfully execute future “greening the fleet” initiatives; and the ability of the Corporation to effect a sale of its renewable energy business and realize the anticipated benefits therefrom.

Algonquin Power & Utilities Corp. - Management Discussion & Analysis 3

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 and the collateral consequences thereof, including the disruption of economic activity, volatility in capital and credit markets and legislative and regulatory responses; 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; 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; 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; 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, dispositions or other initiatives, including with respect to the intended sale of the Corporation's renewable energy business; the possibility of adverse reactions or changes in business relationships or relationships with employees resulting from the announcement or completion of the intended sale of the Corporation's renewable energy business; risks relating to the diversion of the Board’s (as defined herein) or management’s attention in connection with the intended sale of the Corporation's renewable energy business; indebtedness of any entity being acquired by the Corporation; unanticipated expenses and/or cash payments as a result of change of control and/or termination provisions in purchase or sale agreements; 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 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.

Algonquin Power & Utilities Corp. - Management Discussion & Analysis 4

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.

The compositions of Adjusted EBITDA, Adjusted Net Earnings, Adjusted Funds from Operations, and Divisional Operating Profit have been changed from those previously disclosed in AQN’s MD&A for the three and twelve months ended December 31, 2022 to exclude gains and losses on disposition of assets. This change was made as gains and losses on disposition of assets are no longer used by management to evaluate the operating performance of the Company. Comparative figures for these metrics have been adjusted for the new compositions.

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 (including costs related to the 2023 strategic review of the Company's renewable energy business), 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 exclusive of 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), 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, gain or loss on foreign exchange, earnings or loss from discontinued operations, changes in value of investments carried at fair value, gains and losses on disposition of assets, 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 38 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 (including costs related to the 2023 strategic review of the Company's renewable energy business), 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, unrealized mark-to-market revaluation impacts, 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, changes in value of investments carried at fair value, gains and losses on disposition of assets, and other typically non-recurring or unusual items as these are not reflective of the performance of the underlying business

Algonquin Power & Utilities Corp. - Management Discussion & Analysis 5

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 39 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, cash provided by disposition of assets 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 40 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 - 2023 Renewable Energy Group Operating Results on page 33 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 water, 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 - 2023 Regulated Services Group Operating Results on page 23 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, gains and losses on disposition of assets, 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 HLBV income. 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 - 2023 Regulated Services Group Operating Results on page 23 and Renewable Energy Group - 2023 Renewable Energy Group Operating Results on page 33 of this MD&A.

Algonquin Power & Utilities Corp. - Management Discussion & Analysis 6

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. Through its 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.

AQN's current quarterly dividend to shareholders is $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.

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 electric, water distribution and wastewater collection and natural gas utility systems and transmission operations in the United States, Canada, Bermuda and Chile; and the Renewable Energy Group, which primarily owns and operates, or has investments in, a diversified portfolio of non-regulated renewable and thermal energy generation assets.

The Company is pursuing a sale of its renewable energy business. Due to the uncertainty regarding whether, when and on what terms such a sale may be consummated, the Company is not providing 2024 Adjusted Net Earnings per Common Share guidance (see Caution Concerning Non-GAAP Measures).

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.

Algonquin Power & Utilities Corp. - Management Discussion & Analysis 7

Regulated Services Group

The Regulated Services Group primarily operates a diversified portfolio of regulated utility systems located in the United States, Canada, Bermuda and Chile serving approximately 1,256,000 customer connections as at December 31, 2023 (using an average of 2.5 customers per connection, this translates into approximately 3,140,000 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 may seek to deliver long-term growth through 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 ofArkansas, California, Kansas, Missouri, Nevada, New Hampshire and Oklahoma, as well as in Bermuda, which together served approximately 309,000 electric customer connections as at December 31, 2023. 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 572,000 customer connections as at December 31, 2023.

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, 2023.

Below is a breakdown of the Regulated Services Group’s Revenue by geographic area for the twelve months ended December 31, 2023.

Algonquin Power & Utilities Corp. - Management Discussion & Analysis 8

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 located in 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 has economic interests in hydroelectric, wind, solar, renewable natural gas (“RNG”) and thermal facilities which, as of December 31, 2023, had a combined net generating capacity attributable to the Renewable Energy Group of approximately 2.7 GW. Approximately 84% of the electrical output is sold pursuant to long-term contractual arrangements which as of December 31, 2023 had a production-weighted average remaining contract life of approximately 10 years.

In addition, the Renewable Energy Group has an approximately 42% indirect beneficial 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 13 years as of December 31, 2023.

Below is a breakdown of the net generating capacity attributable to the Renewable Energy Group as of December 31, 2023, including the Company’s approximately 42% interest in Atlantica.

Algonquin Power & Utilities Corp. - Management Discussion & Analysis 9

Significant Updates

Operating Results

AQN's 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
	2023	2022	Change	2023	2022	Change
Net earnings (loss) attributable to shareholders	$186.3	$(74.4)	350%	$28.7	$(212.0)	114%
Adjusted Net Earnings1,2	$115.5	$97.6	18%	$372.0	$420.3	(11)%
Adjusted EBITDA1,3	$334.3	$295.5	13%	$1,235.4	$1,192.8	4%
Net earnings (loss) per common share	$0.27	$(0.11)	345%	$0.03	$(0.33)	109%
Adjusted Net Earnings per common share1,2	$0.16	$0.14	14%	$0.53	$0.61	(13)%

1	See Caution Concerning Non-GAAP Measures.
2	Excludes gain on sale of renewable assets of $53.4 million and $54.6 million including tax adjustments, respectively, for the three and twelve months ended December 31, 2022.
3	Excludes gain on sale of renewable assets of $62.8 million and $64.0 million, respectively, for the three and twelve months ended December 31, 2022.

Termination of Acquisition of Kentucky Power Company and AEP Kentucky Transmission Company, Inc.

On April 17, 2023, Liberty Utilities Co. (“Liberty Utilities”), an indirect subsidiary of AQN, mutually agreed with American Electric Power Company, Inc. and AEP Transmission Company, LLC to terminate the stock purchase agreement regarding the acquisition of Kentucky Power Company and AEP Kentucky Transmission Company, Inc. (the “Kentucky Power Transaction Termination”).

Proposed Sale of Renewable Energy Business

On May 11, 2023, the Company announced that the Board had initiated a strategic review of its renewable energy business (the“Strategic Review”). To oversee the strategic review process, the Board formed a Strategic Review Committee, comprised of directors Chris Huskilson (Chair), Amee Chande and Dan Goldberg. On August 10, 2023, the Company announced that it is pursuing a sale of its renewable energy business.

Business Simplification

Aligned with the Company’s previously stated goal to simplify its business, on January 4, 2024, the Company purchased the 50% interest previously owned by Ares (as defined herein) in Liberty Development Energy Solutions B.V. and Liberty Development JV Inc. (collectively “the Joint Ventures”), which the Company used as its non-regulated development platform. As a result, the Company recorded a non-cash loss in 2023 of $18.9 million on development loans to the Joint Ventures for expenditures which would have been eligible for capitalization as development fees under the previous structure. The redeemable non-controlling interest of $306.5 million held by the Joint Ventures was reclassified to long-term debt in 2024.

Additionally, on January 26, 2024, the Company began to wind down its international non-regulated development activities and sold its interest in three development solar assets in Spain to Atlantica (as defined herein) for a nominal amount and recorded a write-down of $1.5 million.

Completion of renewable projects:

Deerfield II Wind Facility

On March 23, 2023, the Renewable Energy Group achieved full commercial operations (“COD”) at its approximately 112 MW Deerfield II Wind Facility, located in Huron County, Michigan. The Deerfield II Wind Facility has agreed to sell all of its output to Siculus, Inc., a subsidiary of Meta, pursuant to a renewable energy purchase agreement. On June 15, 2023, the Company completed the purchase of the remaining 50% equity interest in the Deerfield II Wind Facility which it did not previously own.

Sandy Ridge II Wind Facility

On September 16, 2023, the Renewable Energy Group achieved COD at the approximately 88 MW Sandy Ridge II Wind Facility, located in both Center County and Blair County, Pennsylvania. The Sandy Ridge II Wind Facility has agreed to sell output to a leading technology company pursuant to a renewable energy purchase agreement. On February 15, 2024, the Company completed the purchase of the remaining 50% equity interest in the Sandy Ridge II Wind Facility which it did not previously own.

Algonquin Power & Utilities Corp. - Management Discussion & Analysis 10

Shady Oaks II Wind Facility

On October 10, 2023, the Renewable Energy Group achieved COD at the approximately 108 MW Shady Oaks II Wind Facility, located in Illinois. The Shady Oaks II Wind Facility has agreed to sell output to a leading financial institution pursuant to a renewable energy purchase agreement. The Company holds a 50% equity interest in the facility which is accounted for using the equity method of accounting and holds a purchase option on the remaining 50% equity interest.

New Market Solar Facility

On March 1, 2024, the Renewable Energy Group achieved COD at the approximately 100 MW New Market Solar Facility, located in Ohio. The New Market Solar Facility has agreed to sell output to the City of Cincinnati and a leading electric service provider pursuant to renewable energy purchase agreements. The Company holds a 50% equity interest in the facility which is accounted for using the equity method of accounting and holds a purchase option on the remaining 50% equity interest.

California Rate Cases

During March and April 2023, the Regulated Services Group received final rate case orders at its Apple Valley Water, Park Water and CalPeco Electric systems, with aggregate annual revenue increases of $29.6 million, including approximately $9.7 million due to increases in rate base. A one-time net earnings benefit of approximately $3.7 million from the retroactive impact of the orders was recorded in the first quarter of 2023, with a further $11.4 million in the second quarter of 2023.

Issuance of approximately $850 million of Senior Unsecured Notes

On January 12, 2024, Liberty Utilities completed an offering of $500 million aggregate principal amount of 5.577% senior notes due January 31, 2029 and $350 million aggregate principal amount of 5.869% senior notes due January 31, 2034 (together the “Senior Note Offering”). Liberty Utilities used the net proceeds from the Senior Note Offering to repay indebtedness.

Issuance of approximately $305.5 million of Securitized Utility Tariff Bonds

On January 30, 2024, Empire District Bondco, LLC, a wholly owned subsidiary of The Empire District Electric Company, completed an offering of approximately $180.5 million of aggregate principal amount of 4.943% Securitized Utility Tariff Bonds with a maturity date of January 1, 2035 and $125.0 million aggregate principal amount of 5.091% Securitized Utility Tariff Bonds with a maturity date of January 1, 2039 (collectively, the “Securitization Bonds”), to recover previously incurred qualified extraordinary costs associated with the Midwest Extreme Weather Event (as defined herein) and energy transition costs related to the retirement of the Asbury generating plant. The principal asset securing these bonds is the securitized utility tariff property.

Algonquin Power & Utilities Corp. - Management Discussion & Analysis 11

2023 Fourth Quarter Results From Operations

Key Financial Information	Three months ended December 31
(all dollar amounts in $ millions except per share information)	2023		2022
Revenue	$	666.9	$	748.0
Net earnings (loss) attributable to shareholders	186.3		(74.4)
Cash provided by operating activities	200.7		214.6
Adjusted Net Earnings1	115.5		97.6
Adjusted EBITDA1	334.3		295.5
Adjusted Funds from Operations1	198.9		191.9
Dividends declared to common shareholders	75.6		123.7
Weighted average number of common shares outstanding	688,717,137		683,281,170
Per share
Basic net earnings (loss)	$	0.27	$	(0.11)
Diluted net earnings (loss)	$	0.27	$	(0.11)
Adjusted Net Earnings1	$	0.16	$	0.14
Dividends declared to common shareholders	$	0.11	$	0.18

1 See Caution Concerning Non-GAAP Measures.

For the three months ended December 31, 2023, AQN reported basic net earnings per common share of $0.27 as compared to basic net loss per common share of $0.11 during the same period in 2022, an increase of $0.38.

The net earnings attributable to shareholders of $186.3 million for the three months ended December 31, 2023, was primarily driven by:

•Adjusted Net Earnings of $115.5 million, as further discussed below (see Caution Concerning Non-GAAP Measures); and

•a gain on investments carried at fair value (primarily the Company’s investment in Atlantica) of $122.8 million; partially offset by

•an impairment of $23.5 million on development loans related to the simplification of the Company’s development strategy; and

•other net losses of $13.9 million primarily due to costs associated with the Strategic Review and the pursuit of the sale of the Company’s renewable energy business and write-off of deferred financing costs on the redemption of debt.

The net loss attributable to shareholders of $74.4 million for the three months ended December 31 2022, was primarily driven by:

•Adjusted Net Earnings of $97.6 million, as further discussed below (see Caution Concerning Non-GAAP Measures);

•a gain on asset sales of $62.8 million in the Renewable Energy Group; and

•a gain on derivative financial instruments of $6.4 million; offset by

•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 (as defined herein) primarily as a result of continued challenges with congestion at the facilities (collectively the “2022 Impairment”).

For the three months ended December 31, 2023 AQN reported Adjusted Net Earnings per common share of $0.16 as compared to $0.14 per common share during the same period in 2022, an increase of $0.02 (see Caution Concerning Non-GAAP Measures). Adjusted Net Earnings increased by $17.9 million year over year (see Caution Concerning Non-GAAP Measures). This increase was primarily driven by:

•an increase of $23.9 million in the Regulated Services Group’s operating profit primarily due to regulatory mechanisms and the implementation of new rates;

•an increase of $6.1 million in the Renewable Energy Group’s operating profit primarily due to higher equity income from the Texas Coastal Wind Facilities; and

•an increase in tax recovery of $7.0 million primarily due to higher recognition of investment tax credits (“ITCs”) and production tax credits (“PTCs”) associated with renewable energy projects; partially offset by

Algonquin Power & Utilities Corp. - Management Discussion & Analysis 12

•an increase of $7.3 million in depreciation expense driven by additional capital invested by the Company; and

•an increase of $9.9 million in interest expense, driven by higher interest rates as well as increased borrowings to support growth initiatives.

For the three months ended December 31, 2023, AQN experienced an average exchange rate of Canadian to U.S. dollars of approximately 0.7343 as compared to 0.7364 in the same period in 2022, and an average exchange rate of Chilean pesos to U.S. dollars of approximately 0.0011 for the three months ended December 31, 2023 as compared to 0.0011 for the same period in 2022. As such, any year over year variance in revenue or expenses, in local currency, at any of AQN’s Canadian or 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, 2023, AQN reported total revenue of $666.9 million as compared to $748.0 million during the same period in 2022, a decrease of $81.1 million or 10.8%. The major factors impacting AQN’s revenue in the three months ended December 31, 2023 as compared to the same period in 2022 are as follows:

Algonquin Power & Utilities Corp. - Management Discussion & Analysis 13

(all dollar amounts in $ millions)	Three months ended December 31
Comparative Prior Period Revenue	$	748.0
REGULATED SERVICES GROUP
Existing Facilities
Electricity: Decrease is primarily due to lower wind pricing of approximately $12.0 million and unfavourable weather of approximately $6.0 million at the Empire (MO, KS, AR, OK) Electric System, with the remaining decrease primarily due to lower pass through commodity costs and other costs at the Granite State (NH) and Empire Electric Systems.	(38.6)
Natural Gas: Decrease is primarily due to lower pass through commodity costs.	(54.6)
Water: Increase is primarily due to the inflationary rate increase mechanism at the Suralis (Chile) Water System and organic growth at the Litchfield Park (AZ) Water and Sewer System and Gold Canyon (AZ) Sewer System.	5.4
Other: Decrease is primarily due to lower activity in the non-regulated business in Bermuda.	(4.0)
	(91.8)
Rate Reviews
Electricity: Increase is primarily due to the implementation of new rates at the CalPeco (CA), Empire (OK), Granite State (NH) and Bermuda Electric Light Company (“BELCO”) Electric Systems.	11.1
Natural Gas:	0.4
Water: Increase is primarily due to the implementation of new rates at the Park Water (CA) and Pine Bluff (AR) Water Systems.	5.2
	16.7
Foreign Exchange	0.5
RENEWABLE ENERGY GROUP
Existing Facilities
Hydro:	(0.2)
Wind CA: Decrease is primarily due to lower wind resources across all Canadian wind facilities.	(0.8)
Wind U.S.: Decrease is primarily due to lower wind resources across the majority of the U.S. wind facilities and lower availability revenue at the Maverick Creek Wind Facility.	(8.7)
Solar: Increase is primarily due to favourable capacity revenues across majority of the Solar facilities.	2.8
Thermal & Renewable Natural Gas: Decrease is primarily due to unfavourable overall energy market pricing for the Windsor Locks Thermal Facility partially offset by favourable capacity revenue for the Sanger Thermal Facility.	(0.6)
Other: Decrease is primarily due to lower portfolio optimization revenue.	(2.0)
	(9.5)
New Facilities
Wind U.S: Increase is primarily driven by the Deerfield II Wind Facility (achieved COD in March 2023)	3.3
	3.3
Foreign Exchange	(0.3)
Current Period Revenue	$	666.9

Algonquin Power & Utilities Corp. - Management Discussion & Analysis 14

2023 Annual Results From Operations

Key Financial Information	Twelve months ended December 31
(all dollar amounts in $ millions except per share information)	2023		2022		2021
Revenue	$	2,698.0	$	2,765.0	$	2,274.1
Net earnings (loss) attributable to shareholders	28.7		(212.0)		264.9
Cash provided by operating activities	628.0		619.1		157.5
Adjusted Net Earnings1	372.0		420.3		449.0
Adjusted EBITDA1	1,235.4		1,192.8		1,076.3
Adjusted Funds from Operations1	724.6		790.3		757.9
Dividends declared to common shareholders	301.8		486.0		423.0
Weighted average number of common shares outstanding	688,738,717		677,862,207		622,347,677
Per share
Basic net earnings (loss)	$	0.03	$	(0.33)	$	0.41
Diluted net earnings (loss)	$	0.03	$	(0.33)	$	0.41
Adjusted Net Earnings1	$	0.53	$	0.61	$	0.71
Dividends declared to common shareholders	$	0.43	$	0.71	$	0.67
Total assets	18,374.0		17,627.6		16,797.5
Long-term debt2	8,516.3		7,512.3		6,211.7

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, 2023, AQN reported basic net earnings per common share of $0.03 as compared to basic net loss per common share of $0.33 during the same period in 2022, an increase of $0.36.

The net earnings attributable to shareholders of $28.7 million for the twelve months ended December 31, 2023, was primarily driven by:

•Adjusted Net Earnings of $372.0 million, as further discussed below (see Caution Concerning Non-GAAP Measures); partially offset by

•a loss on investments carried at fair value (primarily the Company’s investment in Atlantica) of $230.0 million; and

•other net losses of $132.9 million, including the Securitization Write-Off (as defined herein) of $63.5 million, and impairment of assets and other losses of $46.5 million incurred as a result of the Kentucky Power Transaction Termination (the “Kentucky Power Impairment”).

The net loss attributable to shareholders of $212.0 million for the twelve months ended December 31, 2022, was primarily driven by:

•Adjusted Net Earnings of $420.3 million, as further discussed below (see Caution Concerning Non-GAAP Measures); and

•a gain on asset sales of $64.0 million in the Renewable Energy Group; offset by

•a loss on investments carried at fair value (primarily the Company’s investment in Atlantica) of $499.1 million; and

•the 2022 Impairment of $235.5 million.

For the twelve months ended December 31, 2023, AQN reported Adjusted Net Earnings per common share of $0.53 compared to $0.61 per common share during the same period in 2022, a decrease of $0.08 (see Caution Concerning Non-GAAP Measures). Adjusted Net Earnings decreased by $48.3 million year over year (see Caution Concerning Non-GAAP Measures), primarily due to:

•a decrease of $26.4 million in the Renewable Energy Group’s HLBV income as a result of the end of PTC eligibility on projects commissioned in 2012;

•a decrease of $12.5 million in the Renewable Energy Group’s operating profit primarily as a result of a 5.3% decrease in wind production compared to the same period in 2022;

Algonquin Power & Utilities Corp. - Management Discussion & Analysis 15

•an increase in earnings attributable to minority interest, exclusive of HLBV, of $34.6 million primarily due to the Company’s sale in the fourth quarter of 2022 of a 49% ownership interest in the Odell, Deerfield and Sugar Creek Wind Facilities;

•an increase in interest expense of $75.1 million, driven by higher interest rates as well as increased borrowings to support growth initiatives;

•an increase in depreciation expense of $11.5 million, driven by additional capital invested by the Company; and

•an increase in administrative expenses of $10.2 million primarily due to technology costs, including costs associated with cyber security; partially offset by

•an increase of $90.5 million in the Regulated Services Group’s operating profit primarily due to the implementation of new rates; and

•an increase in tax recovery of $39.2 million primarily due to higher recognition of ITCs and PTCs associated with renewable energy projects, and the tax impact of lower net earnings.

For the twelve months ended December 31, 2023, AQN experienced an average exchange rate of Canadian to U.S. dollars of approximately 0.7410 as compared to 0.7682 in the same period in 2022, and an average exchange rate of Chilean pesos to U.S. dollars of approximately 0.0012 for the twelve months ended December 31, 2023 as compared to 0.0011 for the same period in 2022. As such, any year-over-year variance in revenue or expenses, in local currency, at any of AQN’s Canadian or 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, 2023, AQN reported total revenue of $2,698.0 million as compared to $2,765.0 million during the same period in 2022, a decrease of $67.0 million or 2.4%. The major factors resulting in the increase in AQN’s revenue for the twelve months ended December 31, 2023 as compared to the same period in 2022 are as follows:

Algonquin Power & Utilities Corp. - Management Discussion & Analysis 16

(all dollar amounts in $ millions)	Twelve months ended December 31
Comparative Prior Period Revenue	$	2,765.0
REGULATED SERVICES GROUP
Existing Facilities
Electricity: Decrease is primarily due to lower wind pricing of approximately $27.0 million and unfavourable weather of approximately $27.0 million at the Empire (MO, KS, AR, OK) Electric System with the remaining decrease primarily due to one-time insurance proceeds for the Neosho Ridge Wind Facility.	(66.7)
Natural Gas: Decrease is primarily due to lower pass through commodity costs.	(72.0)
Water: Increase is primarily due to the inflationary rate increase mechanism at the Suralis (Chile) Water System and organic growth at the Litchfield Park (AZ) Water and Sewer System and Gold Canyon (AZ) Sewer System.	21.3
Other: Decrease is primarily due to lower activity in the non-regulated business in Bermuda.	(5.6)
	(123.0)
Rate Reviews
Electricity: Increase is primarily due to the implementation of new rates at the CalPeco (CA) Electric System retroactive to the first quarter of 2022, as well as the implementation of new rates at the Empire (OK, MO), Granite State (NH) and BELCO (Bermuda) Electric Systems.	84.6
Natural Gas: Increase is primarily due to the implementation of new rates at the EnergyNorth (NH), Peach State (GA), St. Lawrence (NY), Midstates (MO) and Empire (MO) Gas Systems.	5.2
Water: Increase is primarily due to the implementation of new rates at the Park (CA) Water System with one-time retroactive revenues to the third quarter of 2022 and the implementation of new rates at the Pine Bluff (AR) Water System.	12.4
	102.2
Foreign Exchange	3.4
RENEWABLE ENERGY GROUP
Existing Facilities
Hydro: Decrease is primarily driven by lower retail sales in the Maritimes Region and unfavourable energy market pricing for Western Canada Region.	(5.3)
Wind CA: Decrease is primarily due to lower wind resources across all Canadian wind facilities.	(7.6)
Wind U.S.: Decrease is primarily due to lower wind resources across the U.S. wind facilities.	(14.8)
Solar: Decrease is primarily driven by unfavourable energy market pricing across majority of the Solar facilities.	(2.1)
Thermal & Renewable Natural Gas: Decrease is primarily driven by unfavourable energy market pricing at the Sanger and Windsor Locks Thermal Facilities.	(17.3)
Other: Decrease is primarily due to lower portfolio optimization revenue.	(7.4)
	(54.5)
New Facilities
Wind U.S: Increase is primarily driven by the Deerfield II Wind Facility (achieved COD in March 2023).	4.5
Other: Increase is primarily driven by the Blue Hill Wind Facility (achieved COD in April 2022).	4.4
	8.9
Foreign Exchange	(4.0)
Current Period Revenue	$	2,698.0

Algonquin Power & Utilities Corp. - Management Discussion & Analysis 17

2023 Net Earnings Summary

Net earnings attributable to shareholders for the three months ended December 31, 2023 totaled $186.3 million as compared to net loss attributable to shareholders of $74.4 million during the same period in 2022, an increase of $260.7 million or 350.4%. Net earnings attributable to shareholders for the twelve months ended December 31, 2023 totaled $28.7 million as compared to net loss attributable to shareholders of $212.0 million during the same period in 2022, an increase of $240.7 million or 113.5%. The following table outlines the changes to net earnings (loss) attributable to shareholders for the three and twelve months ended December 31, 2023 as compared to the same periods in 2022. 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)	2023			2023
Net loss attributable to shareholders – Prior Period Balance	$	(74.4)		$	(212.0)
Adjusted EBITDA1	38.8			42.6
Net earnings attributable to the non-controlling interest, exclusive of HLBV	(10.5)			(34.6)
Income tax recovery	(27.4)			24.8
Interest expense	(9.9)			(75.1)
Other net losses	(11.8)			(111.5)
Asset impairment charge	136.1			136.1
Impairment of equity-method investee	75.9			75.9
Unrealized loss on energy derivatives included in revenue	(2.6)			(6.6)
Pension and post-employment non-service costs	(0.2)			(8.9)
Change in value of investments carried at fair value	137.5			269.1
Tax equity issuance costs	—			(1.2)
Gain on derivative financial instruments	(5.8)			0.2
Gain on sale of assets	(62.8)			(64.0)
Foreign exchange	10.7			5.4
Depreciation and amortization	(7.3)			(11.5)
Net earnings attributable to shareholders – Current Period Balance	$	186.3		$	28.7
Change in Net Earnings ($)	$	260.7		$	240.7
Change in Net Earnings (%)	350.4		%	113.5		%

1 See Caution Concerning Non-GAAP Measures.

During the three months ended December 31, 2023, cash provided by operating activities totaled $200.7 million as compared to $214.6 million during the same period in 2022, a decrease of $13.9 million primarily as a result of changes in working capital items. During the three months ended December 31, 2023, Adjusted Funds from Operations totaled $198.9 million as compared to Adjusted Funds from Operations of $191.9 million during the same period in 2022, an increase of $7.0 million (see Caution Concerning Non-GAAP Measures).

During the three months ended December 31, 2023, Adjusted EBITDA totaled $334.3 million as compared to $295.5 million during the same period in 2022, an increase of $38.8 million or 13.1% (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, 2023, cash provided by operating activities totaled $628.0 million as compared to $619.1 million during the same period in 2022, an increase of $8.9 million primarily as a result of changes in working capital items. During the twelve months ended December 31, 2023, Adjusted Funds from Operations totaled $724.6 million as compared to Adjusted Funds from Operations of $790.3 million during the same period in 2022, a decrease of $65.7 million (see Caution Concerning Non-GAAP Measures).

Algonquin Power & Utilities Corp. - Management Discussion & Analysis 18

During the twelve months ended December 31, 2023, Adjusted EBITDA totaled $1,235.4 million as compared to $1,192.8 million during the same period in 2022, an increase of $42.6 million or 3.6% (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.

2023 Adjusted EBITDA Summary

Adjusted EBITDA (see Caution ConcerningNon-GAAP Measures) for the three months ended December 31, 2023 totaled $334.3 million as compared to $295.5 million during the same period in 2022, an increase of $38.8 million or 13.1%. Adjusted EBITDA for the twelve months endedDecember 31, 2023 totaled $1,235.4 million as compared to $1,192.8 million during the same period in 2022, an increase of $42.6 million or 3.6%. The breakdown of Adjusted EBITDA by the Company’s main business units and a summary of changes are shown below.

	Three months ended					Twelve months ended
Adjusted EBITDA1 by business units	December 31					December 31
(all dollar amounts in $ millions)	2023			2022		2023			2022
Divisional Operating Profit for Regulated Services Group1	$	238.3		$	214.4	$	954.1		$	863.6
Divisional Operating Profit for Renewable Energy Group1	107.6			101.5		371.8			410.7
Administrative Expenses	(19.3)			(21.2)		(90.4)			(80.2)
Other Income & Expenses	7.7			0.8		(0.1)			(1.3)
Total AQN Adjusted EBITDA1	$	334.3		$	295.5	$	1,235.4		$	1,192.8
Change in Adjusted EBITDA1 ($)	$	38.8				$	42.6
Change in Adjusted EBITDA1 (%)	13.1		%			3.6		%

Change in Adjusted EBITDA1 Breakdown	Three months ended December 31, 2023
(all dollar amounts in $ millions)	Regulated Services		Renewable Energy		Corporate		Total
Prior period balances	$	214.4	$	101.5	$	(20.4)	$	295.5
Existing Facilities and Investments	12.1		5.4		6.9		24.4
New Facilities and Investments	—		(1.4)		—		(1.4)
Rate Reviews	11.7		—		—		11.7
Foreign Exchange Impact	0.1		2.1		—		2.2
Administrative Expenses	—		—		1.9		1.9
Total change during the period	$	23.9	$	6.1	$	8.8	$	38.8
Current period balances	$	238.3	$	107.6	$	(11.6)	$	334.3

Change in Adjusted EBITDA1 Breakdown	Twelve months ended December 31, 2023
(all dollar amounts in $ millions)	Regulated Services		Renewable Energy		Corporate		Total
Prior period balances	$	863.6	$	410.7	$	(81.5)	$	1,192.8
Existing Facilities and Investments	26.7		(45.4)		1.2		(17.5)
New Facilities and Investments	—		9.1		—		9.1
Rate Reviews	62.6		—		—		62.6
Foreign Exchange Impact	1.2		(2.6)		—		(1.4)
Administrative Expenses	—		—		(10.2)		(10.2)
Total change during the period	$	90.5	$	(38.9)	$	(9.0)	$	42.6
Current period balances	$	954.1	$	371.8	$	(90.5)	$	1,235.4

1 See Caution Concerning Non-GAAP Measures.

Algonquin Power & Utilities Corp. - Management Discussion & Analysis 19

REGULATED SERVICES GROUP

The Regulated Services Group primarily operates rate-regulated utilities that as of December 31, 2023 provided distribution services to approximately 1,256,000 customer connections in the electric, natural gas, and water and wastewater sectors which is an increase of approximately 6,000 customer connections as compared to December 31, 2022.

The Regulated Services Group’s strategy is to grow its business organically and through acquisitions. 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
	2023					2022
(all dollar amounts in $ millions)	Assets		Net Utility Sales1		Total Customer Connections2	Assets		Net Utility Sales1		Total Customer Connections2
Electricity	5,142.7		865.7		309,000	5,016.5		813.4		309,000
Natural Gas	1,843.5		354.1		375,000	1,722.6		345.9		375,000
Water and Wastewater	1,678.1		379.5		572,000	1,525.1		346.1		566,000
Other	281.3		51.1			290.7		54.2
Total	$	8,945.6	$	1,650.4	1,256,000	$	8,554.9	$	1,559.6	1,250,000
Accumulated Deferred Income Taxes Liability	$	750.8				$	689.1

1	Net Utility Sales for the twelve months ended December 31, 2023 and 2022. 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, 2023.

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, 2023.

The water and wastewater distribution systems are comprised of regulated water distribution and wastewater collection utility systems and served approximately 572,000 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, 2023.

Algonquin Power & Utilities Corp. - Management Discussion & Analysis 20

2023 Annual Usage Results

Electric Distribution Systems	Three months ended December 31			Twelve months ended December 31
	2023	2022		2023	2022
Average Active Electric Customer Connections For The Period
Residential	262,900	262,500	262500	262,700	261,900
Commercial and industrial	42,900	43,200		42,700	42,800
Total Average Active Electric Customer Connections For The Period	305,800	305,700		305,400	304,700
Customer Usage (GW-hrs)
Residential	635.1	653.3		2,741.5	2,899.6
Commercial and industrial	902.2	924.2		3,820.0	3,849.3
Total Customer Usage (GW-hrs)	1,537.3	1,577.5		6,561.5	6,748.9

For the three months ended December 31, 2023, the electric distribution systems' usage totaled 1,537.3 GW-hrs as compared to 1,577.5 GW-hrs for the same period in 2022, a decrease of 40.2 GW-hrs or 2.5%. The decrease in electricity consumption is primarily due to warmer weather at the Empire Electric System.

For the twelve months ended December 31, 2023, the electric distribution systems' usage totaled 6,561.5 GW-hrs as compared to 6,748.9 GW-hrs for the same period in 2022, a decrease of 187.4 GW-hrs or 2.8%. The decrease in electricity consumption is primarily due to a warmer winter and a cooler summer at the Empire Electric System.

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
	2023	2022	2023	2022
Average Active Natural Gas Customer Connections For The Period
Residential	325,600	321,100	326,500	320,300
Commercial and industrial	40,800	39,100	40,600	38,800
Total Average Active Natural Gas Customer Connections For The Period	366,400	360,200	367,100	359,100
Customer Usage (MMBTU)
Residential	4,358,000	5,433,000	18,822,000	20,912,000
Commercial and industrial	4,894,000	5,723,000	20,215,000	20,607,000
Total Customer Usage (MMBTU)	9,252,000	11,156,000	39,037,000	41,519,000

For the three months ended December 31, 2023, usage at the natural gas distribution systems totaled 9,252,000 MMBTU as compared to 11,156,000 MMBTU during the same period in 2022, a decrease of 1,904,000 MMBTU, or 17.1%. The decrease in customer usage was primarily due to warmer weather at the Mid-States and Empire District Gas Systems.

For the twelve months ended December 31, 2023, usage at the natural gas distribution systems totaled 39,037,000 MMBTU as compared to 41,519,000 MMBTU during the same period in 2022, a decrease of 2,482,000 MMBTU, or 6.0%. The decrease in customer usage was primarily due to warmer weather at the Mid-States, New England Gas and Empire District 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 21

Water and Wastewater Distribution Systems	Three months ended December 31		Twelve months ended December 31
	2023	2022	2023	2022
Average Active Customer Connections For The Period
Wastewater customer connections	55,600	49,100	52,100	48,100
Water distribution customer connections	506,300	504,600	508,400	501,300
Total Average Active Customer Connections For The Period	561,900	553,700	560,500	549,400
Gallons Provided (millions of gallons)
Wastewater treated	869	822	3,350	3,233
Water provided	10,188	9,851	41,435	41,527
Total Gallons Provided (millions of gallons)	11,057	10,673	44,785	44,760

For the three months ended December 31, 2023, the water and wastewater distribution systems provided approximately 10,188 million gallons of water to customers and treated approximately 869 million gallons of wastewater. This is compared to 9,851 million gallons of water provided and 822 million gallons of wastewater treated during the same period in 2022, an increase in total gallons provided of 337 million or 3.4% and an increase in total gallons treated of 47 million or 5.7%. This increase in water provided is primarily due to customer growth at the Litchfield Park Water System and the increase in wastewater treated is primarily due to customer growth at the Litchfield Park and Rio Rico Water Systems.

For the twelve months ended December 31, 2023, the water and wastewater distribution systems provided approximately 41,435 million gallons of water to customers and treated approximately 3,350 million gallons of wastewater. This is compared to 41,527 million gallons of water provided and 3,233 million gallons of wastewater treated during the same period in 2022, a decrease in total gallons provided of 92 million or 0.2% and an increase in total gallons treated of 117 million or 3.6%. This decrease in water provided is mainly due to California drought restrictions at the Park Water System.The increase in wastewater treated is primarily due to customer growth at the Litchfield Park and Rio Rico Water Systems.

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 22

2023Regulated Services Group Operating Results

	Three months ended				Twelve months ended
	December 31				December 31
(all dollar amounts in $ millions)	2023		2022		2023		2022
Revenue
Regulated electricity distribution	$	297.0	$	325.8	$	1,295.5	$	1,278.9
Less: Regulated electricity purchased	(95.7)		(124.2)		(429.8)		(465.5)
Net Utility Sales - electricity1	201.3		201.6		865.7		813.4
Regulated gas distribution	167.4		221.8		621.2		686.7
Less: Regulated gas purchased	(71.6)		(125.5)		(267.1)		(340.8)
Net Utility Sales - natural gas1	95.8		96.3		354.1		345.9
Regulated water reclamation and distribution	100.5		89.0		399.1		364.4
Less: Regulated water purchased	(5.9)		(8.6)		(19.6)		(18.3)
Net Utility Sales - water reclamation and distribution1	94.6		80.4		379.5		346.1
Other revenue2	11.6		14.5		51.1		54.2
Net Utility Sales1,3	403.3		392.8		1,650.4		1,559.6
Operating expenses	(193.4)		(185.8)		(786.6)		(736.5)
Income from long-term investments	11.6		5.2		45.0		21.9
HLBV4	16.8		2.2		45.3		18.6
Divisional Operating Profit1,5	$	238.3	$	214.4	$	954.1	$	863.6

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.
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.

Algonquin Power & Utilities Corp. - Management Discussion & Analysis 23

2023 Fourth Quarter Operating Results

For the three months ended December 31, 2023, the Regulated Services Group reported revenue of $564.9 million (i.e., $297.0 million of regulated electricity distribution, $167.4 million of regulated gas distribution and $100.5 million of regulated water reclamation and distribution) as compared to revenue of $636.6 million in the comparable period in the prior year (i.e., $325.8 million of regulated electricity distribution, $221.8 million of regulated gas distribution and $89.0 million of regulated water reclamation and distribution).

For the three months ended December 31, 2023, the Regulated Services Group reported a Divisional Operating Profit (excluding corporate administration expenses) of $238.3 million as compared to $214.4 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	$	214.4
Existing Facilities
Electricity: Increase is primarily due to higher HLBV income, partially offset by unfavourable weather at the Empire (MO, KS, AR, OK) Electric System.	10.5
Natural Gas:	(0.9)
Water: Decrease is primarily due to higher operating expenses.	(2.8)
Other: Increase is primarily driven by higher interest income on regulatory asset accounts.	5.3
	12.1
Rate Reviews
Electricity: Increase is primarily due to the implementation of new rates at the CalPeco (CA), Empire (OK), Granite State (NH) and BELCO (Bermuda) Electric Systems.	6.1
Natural Gas:	0.4
Water: Increase is primarily due to the implementation of new rates at the Park Water (CA) and Pine Bluff (AR) Water Systems.	5.2
	11.7
Foreign Exchange	0.1
Current Period Divisional Operating Profit1	$	238.3

1 See Caution Concerning Non-GAAP Measures.

Algonquin Power & Utilities Corp. - Management Discussion & Analysis 24

2023 Annual Operating Results

For the twelve months ended December 31, 2023, the Regulated Services Group reported revenue of $2,315.7 million (comprised of $1,295.5 million of regulated electricity distribution revenue, $621.2 million of regulated natural gas distribution revenue and $399.1 million of regulated water reclamation and distribution revenue) as compared to revenue of $2,330.0 million in the same period in the prior year (comprised of $1,278.9 million of regulated electricity distribution revenue, $686.7 million of regulated natural gas distribution revenue and $364.4 million of regulated water reclamation and distribution revenue).

For the twelve months ended December 31, 2023, the Regulated Services Group reported a Divisional Operating Profit (excluding corporate administration expenses) of $954.1 million as compared to $863.6 million in 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)	Twelve months ended December 31
Prior Period Divisional Operating Profit1	$	863.6
Existing Facilities
Electricity: Increase is primarily due to higher HLBV income partially offset by unfavourable weather at the Empire (MO, KS, OK, AR) Electric System and one-time insurance proceeds for the Neosho Ridge Facility.	2.7
Natural Gas:	(0.3)
Water: Increase is primarily due to organic growth at the Litchfield Park (AZ) Water and Sewer System and Gold Canyon (AZ) Sewer System.	2.3
Other: Increase is primarily driven by higher interest income on regulatory asset accounts.	22.0
	26.7
Rate Reviews
Electricity: Increase is primarily due to the implementation of new rates at the CalPeco (CA) Electric System retroactive to the first quarter of 2022, as well as the implementation of new rates at the Empire (OK, MO), Granite State (NH) and BELCO (Bermuda) Electric Systems.	45.0
Natural Gas: Increase is primarily due to the implementation of new rates at the EnergyNorth (NH), Peach State (GA), St. Lawrence (NY), Midstates (MO) and Empire (MO) Gas Systems.	5.2
Water: Increase is primarily due to the implementation of new rates at the Park (CA) Water System with one-time retroactive revenues to the third quarter of 2022 and the implementation of new rates at the Pine Bluff (AR) Water System.	12.4
	62.6
Foreign Exchange	1.2
Current Period Divisional Operating Profit1	$	954.1

1 See Caution Concerning Non-GAAP Measures.

Algonquin Power & Utilities Corp. - Management Discussion & Analysis 25

Regulatory Proceedings

The following table summarizes the major regulatory proceedings currently underway or completed or effective in 2023 within the Regulated Services Group.

Utility	Jurisdiction	Regulatory Proceeding Type	Rate Request (millions)	Current Status
Completed Rate Reviews
BELCO	Bermuda	General Rate Case ("GRC")	$34.8	On September 30, 2021, 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. On February 19, 2024, the Bermuda Supreme Court issued an order denying the BELCO appeal. Any further appeal must be filed by April 4, 2024.
Apple Valley 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 CPUC issued a Final Order authorizing an annual revenue increase of $1.5 million in 2022, and subsequent expected increases of $1.6 million and $1.5 million in 2023 and 2024, respectively. New rates became effective April 7, 2023 retroactive to July 1, 2022.
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 in 2022, and subsequent expected increases of $1.5 million and $1.5 million in 2023 and 2024, respectively. New rates became effective April 7, 2023 retroactive to July 1, 2022.
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. The CPUC issued a Final Order on April 27, 2023 authorizing an annual revenue increase of $27.0 million. New rates became effective July 1, 2023 retroactive to January 2022.

Algonquin Power & Utilities Corp. - Management Discussion & Analysis 26

Utility	Jurisdiction	Regulatory Proceeding Type	Rate Request (millions)	Current Status
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 and St. Lawrence Gas filed rebuttal testimony on June 24, 2022. On March 31, 2023, a joint proposal was filed by the parties resolving all issues. On June 22, 2023, the Commission issued an Order approving the terms of the joint proposal and authorizing a revenue increase of $5.2 million to be implemented over the course of 2023-2025. New rates became effective July 1, 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. On August 4, 2023, the Arkansas Public Service Commission issued an Order approving a unanimous settlement agreement filed by the parties authorizing an annual revenue increase of $3.4 million. New rates became effective August 15, 2023.
Gas New Brunswick	New Brunswick	GRC	-$0.6	On March 3, 2023, filed an application for a revenue decrease of $0.6 million based on the Energy & Utilities Board's recent decisions authorizing a capital structure of 45% equity and an ROE of 9.8%. On September 21, 2023 the Energy & Utilities Board issued a decision authorizing a revenue decrease of $0.7 million.
Empire Electric	Arkansas	GRC	$7.3	On February 14, 2023, filed an application seeking an increase in revenues of $7.3 million based on an ROE of 10.25% and an equity ratio of 56% to be phased in over three years. On December 7, 2023, the Arkansas Public Service Commission issued an Order approving the settlement agreement authorizing a revenue increase of $5.3 million. New rates became effective January 1, 2024.
Various	Various	Various	$0.1	On February 22, 2023, the Arizona Corporation Commission issued an Order approving the proposed consolidation of rates and tariffs for two wastewater utilities and new rates to be effective March 1, 2023.
Pending Rate Reviews
Granite State Electric	New Hampshire	GRC	$15.5	On May 5, 2023, filed an application seeking a permanent increase in revenues of $15.5 million based on an ROE of 10.35% and an equity ratio of 55%. Temporary rates of $5.5 million were implemented on July 1, 2023. On December 13, 2023, the Department of Energy filed a motion seeking to dismiss the case. An evidentiary hearing was held on January 23, 2024. The case has been stayed by the New Hampshire Public Utilities Commission (“NHPUC”) until April 15, 2024 so that it may contemplate the motion and so that the Company can provide the Commission with a third-party review of the financial information within the rate application.

Algonquin Power & Utilities Corp. - Management Discussion & Analysis 27

Utility	Jurisdiction	Regulatory Proceeding Type	Rate Request (millions)	Current Status
New York Water	New York	GRC	$39.7	On May 4, 2023, filed an application seeking an increase in revenues of $39.7 million based on an ROE of 10% and an equity ratio of 50%.
EnergyNorth Gas	New Hampshire	GRC	$27.5	On July 27, 2023, filed an application seeking an increase in revenues of $27.5 million based on an ROE of 10.35% and an equity ratio of 55%. Temporary rates of $8.7 million were approved by the Commission on October 31, 2023. The temporary rate increase is retroactive to October 1, 2023. On February 5, 2024, the Company requested that the NHPUC stay the case until April 12, 2024 so that the Company can provide the Commission with a third-party review of the financial information upon which the revenue requirement is predicated. On February 16, 2024, the Department of Energy filed a motion seeking to dismiss the case. A hearing was held on March 6, 2024 on the motion to dismiss and the request for the stay.
Midstates Gas	Illinois	GRC	$5.3	On December 20, 2023, filed an application seeking an increase in revenues of $5.3 million based on an ROE of 10.80% and an equity ratio of 54%.
Rio Rico Water & Sewer, Bella Vista Water, Beardsley Water, Cordes Lakes Water	Arizona	GRC	$5.4	On December 28, 2023, filed an application seeking an increase in revenues of $5.4 million based on an ROE of 10.95% and an equity ratio of 54%.
Park Water	California	GRC	$9.3	On January 2, 2024, filed an application seeking an increase in revenues of $9.3 million based on an ROE of 9.35% and an equity ratio of 57%.
Apple Valley Water	California	GRC	$3.1	On January 2, 2024, filed an application seeking an increase in revenues of $3.1 million based on an ROE of 9.35% and an equity ratio of 57%.

Proceedings related to the Midwest Extreme Weather Event and the Retirement of Asbury

The February 2021 extreme winter storm conditions experienced in Texas and parts of the central U.S. (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 Missouri Public Service Commission ("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.

Algonquin Power & Utilities Corp. - Management Discussion & Analysis 28

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 “Securitization Order”). 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. Oral arguments were heard in July 2023. On August 1, 2023, the court affirmed the amount eligible for securitization of $290.4 million as well as certain additional carrying costs to the date of issuance. The Company completed its issuance of Securitization Bonds in the aggregate principal amount of $305.5 million on January 30, 2024 in line with the MPSC’s order to recover the costs associated with the Midwest Extreme Weather Event and the remaining book value of Asbury. The MPSC's order excluded a portion of carrying costs and taxes associated with Asbury, and the Company incurred a one-time net loss of $63.5 million ($48.5 million net of tax) (the “Securitization Write-Off”).

Algonquin Power & Utilities Corp. - Management Discussion & Analysis 29

RENEWABLE ENERGY GROUP

2023 Electricity Generation Performance
	Long-Term Average Resource1	Three months ended December 31		Long-Term Average Resource1	Twelve months ended December 31
(Performance in GW-hrs sold)		2023	2022		2023	2022
Hydro Facilities:
Maritime Region	37.6	43.3	48.2	148.2	157.1	149.1
Quebec Region	72.6	76.7	74.1	273.3	294.8	292.0
Ontario Region	26.2	29.9	27.9	120.4	107.7	116.0
Western Region	12.6	11.0	10.2	65.0	51.8	52.1
	149.0	160.9	160.4	606.9	611.4	609.2
Canadian Wind Facilities:
St. Damase	22.7	19.1	23.4	76.9	64.0	77.7
St. Leon	121.4	116.3	125.4	430.2	373.6	435.0
Red Lily2	24.1	24.9	25.3	88.5	80.0	90.8
Morse	30.5	29.6	26.1	108.8	92.8	103.7
Amherst	67.9	60.2	67.6	229.8	187.0	219.5
Blue Hill3	200.4	144.5	140.2	683.2	501.4	464.2
EBR3	21.0	15.5	21.1	74.4	53.7	71.0
	488.0	410.1	429.1	1,691.8	1,352.5	1,461.9
U.S. Wind Facilities:
Sandy Ridge	43.6	34.9	11.7	158.3	114.4	105.5
Minonk	189.8	166.4	208.5	673.7	580.4	696.9
Senate	140.0	115.3	114.2	520.4	463.2	490.0
Shady Oaks	100.5	94.7	114.9	355.6	318.7	362.2
Odell5	238.0	203.2	250.9	831.8	738.7	869.3
Deerfield5	167.9	151.3	168.8	546.0	481.3	554.9
Sugar Creek5	212.6	177.5	193.0	724.8	606.9	661.4
Maverick Creek	480.2	354.0	362.6	1,920.6	1,472.1	1,620.9
Deerfield II6	116.0	89.5	—	281.6	181.1	—
Sandy Ridge II9	75.1	64.7	—	87.8	70.5	—
Shady Oaks II10	95.8	79.2	—	95.8	79.2	—
	1,859.5	1,530.7	1,424.6	6,196.4	5,106.5	5,361.1
Solar Facilities:
Cornwall	2.2	1.8	2.4	14.7	14.0	14.8
Bakersfield	13.0	9.4	9.9	77.2	61.9	67.2
Great Bay	37.6	46.6	44.1	205.7	211.7	214.7
Altavista	31.4	35.0	33.0	164.4	169.0	167.7
Croton	0.9	1.0	1.1	5.4	5.1	5.4
Dalewood7	0.2	0.1	—	1.0	0.8	—
Hayhurst New Mexico11	5.8	6.2	—	5.8	6.2	—
	91.1	100.1	90.5	474.2	468.7	469.8
Renewable Energy Performance	2,587.6	2,201.8	2,104.6	8,969.3	7,539.1	7,902.0
Thermal Facilities:
Windsor Locks	N/A7	30.9	29.7	N/A7	118.0	127.5
Sanger	N/A7	0.8	—	N/A7	11.9	149.1
		31.7	29.7		129.9	276.6
Total Performance12		2,233.5	2,134.3		7,669.0	8,178.6

Algonquin Power & Utilities Corp. - Management Discussion & Analysis 30

1	Long-Term Average Resource ("LTAR") is based on weather resource studies done at the inception of each project.
2	AQN owns a 75% equity interest but accounts for the facility using the equity method. Figures show full energy produced by the facility.
3	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 LTAR and full energy produced by the facility during the quarter.
4	AQN owns a 50% equity interest but accounts for the facility using the equity method. Figures show full energy produced by the facility during the quarter.

5	AQN owns a 51% equity interest in the Sugar Creek, Odell and Deerfield Wind Facilities but consolidates the facilities for accounting purposes. Figures show full energy produced by the facilities during the quarter.
6	The Deerfield II Wind Facility achieved COD on March 23, 2023. Prior to June 15, 2023, AQN owned a 50% interest in the facility. On June 15, 2023, AQN acquired the remaining 50% interest that it did not previously own. Figures show full energy produced by the facility during the quarter.
7	The Dalewood Solar Facility achieved COD on December 21, 2022.
8	Natural gas fired co-generation facility.
9	The Sandy Ridge II Wind Facility achieved COD on September 16, 2023. AQN owns a 50% interest in the facility, but accounts for the facility using the equity method. Figures show full energy produced by the facility during the quarter.
10	The Shady Oaks II Wind Facility achieved COD on October 10, 2023. AQN owns a 50% interest in the facility, but accounts for the facility using the equity method. Figures show full energy produced by the facility during the quarter.
11	The Hayhurst New Mexico Solar Facility achieved COD on November 6, 2023. AQN owns 50% equity interest but accounts for the facility using the equity method. Figures show expected LTAR and full energy produced by the facility during the quarter.
12	Total Performance represents actual energy produced by each facility. Lower than expected turbine availability will contribute to generation shortfalls relative to LTAR in some instances. The Company recognizes availability revenue when such shortfalls are compensated for under various long term service and maintenance agreements. The compensated generation is not reflected in the actual energy produced by each facility.

2023 Fourth Quarter Renewable Energy Group Performance

For the three months ended December 31, 2023, the Renewable Energy Group generated 2,233.5 GW-hrs of electricity as compared to 2,134.3 GW-hrs during the same period in 2022.

For the three months ended December 31, 2023, the hydro facilities generated 160.9 GW-hrs of electricity as compared to 160.4 GW-hrs produced in the same period in 2022, an increase of 0.3%. Electricity generated represented 108.0% of LTAR as compared to 107.7% during the same period in 2022.

For the three months ended December 31, 2023, the wind facilities produced 1,940.8GW-hrs of electricity as compared to 1,853.7 GW-hrs produced in the same period in 2022, an increase of 4.70%. Excluding the Deerfield II Wind Facility, which achieved COD on March 23, 2023, the Sandy Ridge II Wind Facility, which achieved COD on September 16, 2023, and the Shady Oaks II Wind Facility, which achieved COD on October 10, 2023, production was 7.9% below the same period last year. The wind facilities, including new facilities, generated electricity equal to 82.7%of LTAR as compared to 90.0% during the same period in 2022.

For the three months ended December 31, 2023, the solar facilities generated 100.1 GW-hrs of electricity as compared to 90.5 GW-hrs of electricity in the same period in 2022, an increase of 10.6%. Excluding the Dalewood Solar Facility, which achieved COD on December 21, 2022, and the Hayhurst New Mexico Solar Facility, which achieved COD on November 6, 2023, production was 3.6% above the same period last year. The solar facilities, including new facilities, generated electricity equal to 109.9% of LTAR as compared to 106.3% in the same period in 2022.

For the three months ended December 31, 2023, the thermal facilities generated 31.7 GW-hrs of electricity as compared to 29.7 GW-hrs of electricity during the same period in 2022. During the same period, the Windsor Locks Thermal Facility generated 144.9 billion lbs of steam as compared to 130.5 billion lbs of steam during the same period in 2022.

Algonquin Power & Utilities Corp. - Management Discussion & Analysis 31

2023 Annual Renewable Energy Group Performance

For the twelve months ended December 31, 2023, the Renewable Energy Group generated 7,669.0 GW-hrs of electricity as compared to 8,178.6 GW-hrs during the same period in 2022.

For the twelve months ended December 31, 2023, the hydro facilities generated 611.4 GW-hrs of electricity as compared to 609.2 GW-hrs produced in the same period in 2022, an increase of 0.4%. Electricity generated represented 100.7% of LTAR as compared to 100.4% during the same period in 2022.

For the twelve months ended December 31, 2023, the wind facilities produced 6,459.0GW-hrs of electricity as compared to 6,823.0 GW-hrs produced in the same period in 2022, a decrease of 5.3%. Excluding the Blue Hill Wind Facility, which achieved COD on April 14, 2022, the Deerfield II Wind Facility, which achieved COD on March 23, 2023, the Sandy Ridge II Wind Facility, which achieved COD on September 16, 2023, and the Shady Oaks II Wind Facility, which achieved COD on October 10, 2023, production was 11.5% below the same period last year. The wind facilities generated electricity equal to 81.9% of LTAR as compared to 93.5%during the same period in 2022.

For the twelve months ended December 31, 2023, the solar facilities generated 468.7 GW-hrs of electricity as compared to 469.8 GW-hrs of electricity produced in the same period in 2022, a decrease of 0.2%. Excluding the Dalewood Solar Facility, which achieved COD on December 21, 2022, and the Hayhurst New Mexico Solar Facility, which achieved COD on November 6, 2023, production was 1.7% below the same period last year. The solar facilities generated electricity equal to 98.8% of LTAR as compared to 100.5% in the same period in 2022.

For the twelve months ended December 31, 2023, the thermal facilities generated 129.9 GW-hrs of electricity as compared to 276.6 GW-hrs of electricity during the same period in 2022. For the twelve months ended December 31, 2023, the Windsor Locks Thermal Facility generated 523.9 billion lbs of steam as compared to 520.2 billion lbs of steam during the same period in 2022.

Algonquin Power & Utilities Corp. - Management Discussion & Analysis 32

2023 Renewable Energy Group Operating Results
	Three months ended				Twelve months ended
	December 31				December 31
(all dollar amounts in $ millions)	2023		2022		2023		2022
Revenue1
Hydro	$	9.0	$	13.1	$	35.4	$	51.5
Wind	59.4		64.5		199.5		221.4
Solar	6.6		2.8		31.0		30.1
Thermal	7.1		8.2		30.4		47.8
Total Non-Regulated Energy Sales	$	82.1	$	88.6	$	296.3	$	350.8
Less:
Cost of Sales - Energy2	(0.3)		(0.2)		(2.6)		(7.1)
Cost of Sales - Thermal	(3.7)		(5.2)		(16.9)		(34.5)
Net Energy Sales 3,4	$	78.1	$	83.2	$	276.8	$	309.2
Renewable Energy Credits5	5.9		7.6		27.5		27.8
Other Revenue	2.0		0.3		5.9		0.6
Total Net Revenue	$	86.0	$	91.1	$	310.2	$	337.6
Expenses & Other Income
Operating expenses	(30.5)		(31.7)		(119.0)		(114.5)
Dividend, interest, equity and other income6	32.8		21.6		109.3		91.2
HLBV income7	19.3		20.5		71.3		96.4
Divisional Operating Profit3,8,9	$	107.6	$	101.5	$	371.8	$	410.7

1	Many of the Renewable Energy Group’s 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.
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 renewable energy certificates (“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, 2023, the Renewable Energy Group's eligible facilities generated 3,299.0 GW-hrs representing approximately $92.4 million in PTCs earned as compared to 4,998.9 GW-hrs representing $130.0 million in PTCs earned during the same period in 2022. 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 which has lowered 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 33

2023 Fourth Quarter Operating Results

For the three months ended December 31, 2023, the Renewable Energy Group’s facilities generated operating revenue of $82.1 million (i.e., non-regulated energy sales) as compared to $88.6 million in the comparable period in the prior year.

For the three months ended December 31, 2023, the Renewable Energy Group's facilities generated $107.6 million of Divisional Operating Profit as compared to $101.5 million during the same period in 2022, which represents an increase of $6.1 million or 6.0% (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	$	101.5
Existing Facilities and Investments
Hydro: Increase is primarily driven by lower operating expenses across Hydro facilities	1.8
Wind CA: Decrease is primarily due to lower wind resources across all Canadian wind facilities.	(1.9)
Wind U.S.: Decrease is primarily due to lower wind resources across the majority of the U.S. wind facilities and lower availability revenue at the Maverick Creek Wind Facility. This is partially offset by lower operating expenses across most U.S. wind facilities.	(6.1)
Solar: Increase is primarily due to favourable HLBV income as a result of tax attribute eligibility on the Great Bay Solar I Facility commissioned in 2018 ending and favourable capacity revenues for majority of the Solar Facilities.	4.3
Thermal & Renewable Natural Gas: Increase is primarily driven by favourable capacity revenues at the Sanger Thermal Facility.	1.7
Investments and Other: Increase is primarily due to higher equity income from the Texas Coastal Wind Facilities partially offset by unfavourable portfolio optimization revenue.	5.6
	5.4
New Facilities and Investments
Wind U.S: Decrease is primarily driven by the Deerfield II Wind Facility HLBV loss (achieved COD in March 2023)	(1.4)
	(1.4)
Foreign Exchange	2.1
Current Period Divisional Operating Profit1	$	107.6

1 See Caution Concerning Non-GAAP Measures.

Algonquin Power & Utilities Corp. - Management Discussion & Analysis 34

2023 Annual Operating Results

For the twelve months ended December 31, 2023, the Renewable Energy Group’s facilities generated operating revenue of $296.3 million (i.e., non-regulated energy sales) as compared to $350.8 million in the comparable period in the prior year.

For the twelve months endedDecember 31, 2023, the Renewable Energy Group’s facilities generated $371.8 million of Divisional Operating Profitas compared to $410.7 million during the same period in 2022, which represents a decrease of $38.9 million or 9.5% (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	$	410.7
Existing Facilities
Hydro: Increase is primarily driven by lower purchased power in the Maritimes Region and lower operating expenses across Hydro Facilities.	4.7
Wind CA: Decrease is primarily due to lower wind resources across all Canadian wind facilities.	(10.0)
Wind U.S.: Decrease is primarily driven by lower wind resources across all U.S. wind facilities and lower HLBV income as a result of tax attribute eligibility on projects commissioned in 2012 ending.	(41.3)
Solar: Decrease is primarily driven by unfavourable energy market pricing across majority of the Solar facilities. This is partially offset favourable capacity revenues across majority of the Solar facilities.	(4.8)
Thermal & Renewable Natural Gas:	(0.2)
Investments and Other: Increase is primarily due to higher equity income from the Texas Coastal Wind Facilities partially offset by unfavourable portfolio optimization revenue.	6.2
	(45.4)
New Facilities and Investments
Wind U.S.: Increase is primarily driven by the Deerfield II Wind Facility (achieved COD in March 2023).	2.5
Thermal & RNG: Increase is primarily driven by the Five Star and Bach RNG Facilities (Fully acquired in August 2022).	2.3
Other: Increase is primarily driven by the Blue Hill Wind Facility (achieved COD in April 2022).	4.3
	9.1
Foreign Exchange	(2.6)
Current Period Divisional Operating Profit1	$	371.8

1 See Caution Concerning Non-GAAP Measures.

Algonquin Power & Utilities Corp. - Management Discussion & Analysis 35

AQN: CORPORATE AND OTHER EXPENSES

	Three months ended				Twelve months ended
	December 31				December 31
(all dollar amounts in $ millions)	2023		2022		2023		2022
Corporate and other expenses:
Administrative expenses	$	19.3	$	21.2	$	90.4	$	80.2
Loss on foreign exchange	3.4		14.1		8.4		13.8
Interest expense	87.9		78.0		353.7		278.6
Depreciation and amortization	122.1		114.8		467.0		455.5
Change in value of investments carried at fair value	(122.8)		14.7		230.0		499.1
Interest, dividend, equity, and other loss (income)1	(7.8)		(2.5)		0.7		3.2
Pension and other post-employment non-service costs	4.8		4.6		19.9		11.0
Other net losses	13.9		2.1		132.9		21.4
Gain on derivative financial instruments	(0.6)		(6.4)		(4.6)		(4.4)
Income tax recovery	(1.2)		(28.6)		(86.3)		(61.5)

1 Excludes income directly pertaining to the Regulated Services and Renewable Energy Groups (disclosed in the relevant sections).

2023 Fourth Quarter Corporate and Other Expenses

For the three months ended December 31, 2023, administrative expenses totaled $19.3 million as compared to $21.2 million in the same period in 2022. The decrease is primarily due to timing of expenses.

For the three months ended December 31, 2023, interest expense totaled $87.9 million as compared to $78.0 million in the same period in 2022. The increase was approximately one-quarter due to the funding of capital deployed in 2023 and three-quarters due to the increase in interest rates on variable rate borrowings.

For the three months ended December 31, 2023, depreciation expense totaled $122.1 million as compared to $114.8 million in the same period in 2022.

For the three months ended December 31, 2023, change in investments carried at fair value totaled a gain of $122.8 million as compared to a loss of $14.7 million in the same period in 2022. 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, 2023, pension and post-employment non-service costs totaled $4.8 million as compared to $4.6 million in the same period in 2022. The increase was primarily due to higher interest costs and lower expected return on plan assets.

For the three months ended December 31, 2023, other net losses were $13.9 million as compared to $2.1 million in the same period in 2022. The increase was primarily due to costs associated with the pursuit of a sale of the Company’s renewable energy business of $5.0 million, and $8.5 million for write-off of deferred financing costs on the redemption of the Company’s 6.875% fixed-to-floating subordinated notes – Series 2018-A (the “2018 Subordinated Notes”). See Note 19 in the annual consolidated financial statements.

For the three months ended December 31, 2023, the gain on derivative financial instruments totaled $0.6 million as compared to a gain of $6.4 million in the same period in 2022. AQN uses derivative instruments to manage exposure to changes in commodity prices, foreign exchange rates, and interest rates. The gains in the fourth quarter of both 2023 and 2022 were primarily related to mark-to-markets on interest rate derivatives.

For the three months ended December 31, 2023, an income tax recovery of $1.2 million was recorded as compared to an income tax recovery of $28.6 million during the same period in 2022. The decrease in income tax recovery was primarily due to increased earnings and the tax impact associated with the change in fair value of the investment in Atlantica. The decrease in income tax recovery was partially offset by the tax impact associated with the valuation allowance recorded on the Renewable Energy Group in 2022 and accrued tax credits. For the three months ended December 31, 2023, the Company accrued $19.3 million of ITCs and PTCs primarily associated with renewable energy projects that had been placed in service by the end of 2023 as compared to a $4.7 million recorded in the same period in 2022.

Algonquin Power & Utilities Corp. - Management Discussion & Analysis 36

2023 Annual Corporate and Other Expenses

During the twelve months ended December 31, 2023, administrative expenses totaled $90.4 million as compared to $80.2 million in the same period in 2022. The increase is primarily due to technology costs, including costs associated with cyber security, as well as costs previously shown as operating expenses now shown within administrative expenses as the Company increased usage of its shared services model in an effort to drive future operational efficiencies.

For the twelve months ended December 31, 2023, interest expense totaled $353.7 million as compared to $278.6 million in the same period in 2022. The increase was approximately one-quarter due to the funding of capital deployed in 2023 and three-quarters due to the increase in interest rates on variable rate borrowings.

For the twelve months ended December 31, 2023, depreciation expense totaled $467.0 million as compared to $455.5 million in the same period in 2022. The increase was primarily due to higher overall property, plant and equipment.

For the twelve months ended December 31, 2023, change in investments carried at fair value totaled a loss of $230.0 million as compared to a loss of $499.1 million in the same period in 2022. 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, 2023, pension and post-employment non-service costs totaled $19.9 million as compared to $11.0 million in the same period in 2022. The increase was primarily due to higher interest cost and lower expected return on plan assets.

For the twelve months ended December 31, 2023, other net losses were $132.9 million as compared to $21.4 million in the same period in 2022. The increase was primarily due to the $46.5 million Kentucky Power Impairment, the Securitization Write-Off of $63.5 million, write-off of deferred financing costs on the redemption of the 2018 Subordinated Notes of $8.5 million and costs associated with the Strategic Review and the pursuit of a sale of the Company’s renewable energy business of $12.5 million, partially offset by a $12.0 million contingent gain resulting from settlement of the purchase price of the Suralis Water System acquired in 2020. See Note 19 in the annual consolidated financial statements.

For the twelve months ended December 31, 2023, the gain on derivative financial instruments totaled $4.6 million as compared to a gain of $4.4 million in the same period in 2022. AQN uses derivative instruments to manage exposure to changes in commodity prices, foreign exchange rates, and interest rates. The gains for both the twelve months ended December 31, 2023 and for the twelve months ended December 31, 2022 were primarily related to mark-to-markets on interest rate derivatives.

For the twelve months ended December 31, 2023, an income tax recovery of $86.3 million was recorded as compared to an income tax recovery of $61.5 million during the same period in 2022. The increase in income tax recovery was primarily due to the tax impact associated with the valuation allowance recorded on the Renewable Energy Group in 2022 and accrued tax credits. These tax recoveries were partially offset by the tax impact associated with the change in fair value of the investment in Atlantica and an increase in earnings. For the twelve months ended December 31, 2023, the Company accrued $54.8 million of ITCs and PTCs primarily associated with renewable energy projects that had been placed in service by the end of 2023 as compared to $18.4 million recorded in the same period in 2022.

Algonquin Power & Utilities Corp. - Management Discussion & Analysis 37

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				Twelve months ended
	December 31				December 31
(all dollar amounts in $ millions)	2023		2022		2023		2022
Net earnings (loss) attributable to shareholders	$	186.3	$	(74.4)	$	28.7	$	(212.0)
Add (deduct):
Net earnings attributable to the non-controlling interest, exclusive of HLBV	16.5		6.0		53.5		18.9
Income tax recovery	(1.2)		(28.6)		(86.3)		(61.5)
Interest expense	87.9		78.0		353.7		278.6
Other net losses1	13.9		2.1		132.9		21.4
Unrealized loss (gain) on energy derivatives included in revenue2	0.5		(2.1)		7.5		0.9
Asset impairment charge	23.5		159.6		23.5		159.6
Impairment of equity-method investee	—		75.9		—		75.9
Pension and post-employment non-service costs	4.8		4.6		19.9		11.0
Change in value of investments carried at fair value3	(122.8)		14.7		230.0		499.1
Costs related to tax equity financing	—		—		1.2		—
Gain on derivative financial instruments	(0.6)		(6.4)		(4.6)		(4.4)
Gain on sale of renewable assets	—		(62.8)		—		(64.0)
Loss on foreign exchange	3.4		14.1		8.4		13.8
Depreciation and amortization	122.1		114.8		467.0		455.5
Adjusted EBITDA	$	334.3	$	295.5	$	1,235.4	$	1,192.8

1	See Note 19 in the annual consolidated financial statements.
2	Includes $7.1 million of unrealized losses on derivatives included in equity income for the twelve months ended December 31, 2023. See Note 8 in the annual consolidated financial statements.
3	See Note 8 in the annual consolidated financial statements.

Algonquin Power & Utilities Corp. - Management Discussion & Analysis 38

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				Twelve months ended
	December 31				December 31
(all dollar amounts in $ millions except per share information)	2023		2022		2023		2022
Net earnings (loss) attributable to shareholders	$	186.3	$	(74.4)	$	28.7	$	(212.0)
Add (deduct):
Gain on derivative financial instruments	(0.6)		(6.4)		(4.6)		(4.4)
Gain on sale of renewable assets	—		(62.8)		—		(64.0)
Other net losses1	13.9		2.1		132.9		21.4
Asset impairment charge	23.5		159.6		23.5		159.6
Impairment of equity-method investee	—		75.9		—		75.9
Loss on foreign exchange	3.4		14.1		8.4		13.8
Unrealized loss (gain) on energy derivatives included in revenue2	0.5		(2.1)		7.5		0.9
Change in value of investments carried at fair value3	(122.8)		14.7		230.0		499.1
Costs related to tax equity financing	—		—		1.2		—
Adjustment for taxes related to above	11.3		(23.1)		(55.6)		(70.0)
Adjusted Net Earnings	$	115.5	$	97.6	$	372.0	$	420.3
Adjusted Net Earnings per common share	$	0.16	$	0.14	$	0.53	$	0.61

1	See Note 19 in the annual consolidated financial statements.
2	Includes $7.1 million of unrealized losses on derivatives included in equity income for the twelve months ended December 31, 2023. See Note 8 in the annual consolidated financial statements.
3	See Note 8 in the annual consolidated financial statements.

For the three months ended December 31, 2023, Adjusted Net Earnings totaled $115.5 million as compared to Adjusted Net Earnings of $97.6 million for the same period in 2022, an increase of $17.9 million.

For the twelve months ended December 31, 2023, Adjusted Net Earnings totaled $372.0 million as compared to Adjusted Net Earnings of $420.3 million for the same period in 2022,a decrease of $48.3 million.

Algonquin Power & Utilities Corp. - Management Discussion & Analysis 39

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				Twelve months ended
	December 31				December 31
(all dollar amounts in $ millions)	2023		2022		2023		2022
Cash provided by operating activities	$	200.7	$	214.6	$	628.0	$	619.1
Add (deduct):
Changes in non-cash operating items	(1.8)		41.2		86.3		221.6
Production based cash contributions from non-controlling interests	—		—		9.1		6.2
Gain on sale of renewable assets	—		(62.8)		—		(64.0)
Costs related to tax equity financing	—		—		1.2		—
Acquisition-related costs	—		(1.1)		—		7.4
Adjusted Funds from Operations	$	198.9	$	191.9	$	724.6	$	790.3

For the three months ended December 31, 2023, Adjusted Funds from Operations totaled $198.9 million as compared to Adjusted Funds from Operations of $191.9 million for the same period in 2022, an increase of $7.0 million primarily due to higher cash interest paid in 2023.

For the twelve months ended December 31, 2023, Adjusted Funds from Operations totaled $724.6 million as compared to Adjusted Funds from Operations of $790.3 million for the same period in 2022, a decrease of $65.7 million primarily due to higher cash interest paid in 2023.

SUMMARY OF PROPERTY, PLANT AND EQUIPMENT EXPENDITURES

	Three months ended				Twelve months ended
	December 31				December 31
(all dollar amounts in $ millions)	2023		2022		2023		2022
Regulated Services Group
Rate Base Maintenance1	89.4		$	78.5	347.4		316.5
Rate Base Growth	137.7		253.5		394.6		669.1
Property, Plant & Equipment Acquired2	—		—		—		609.3
	$	227.1	$	332.0	$	742.0	$	1,594.9
Renewable Energy Group	$	32.6	$	103.4	$	320.3	$	176.6
Total Capital Expenditures	$	259.7	$	435.4	$	1,062.3	$	1,771.5

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.

Algonquin Power & Utilities Corp. - Management Discussion & Analysis 40

2023 Fourth Quarter Property, Plant and Equipment Expenditures

During the three months ended December 31, 2023, the Regulated Services Group made capital expenditures of $227.1 million as compared to $332.0 million during the same period in 2022. The Regulated Services Group's investments during the fourth quarter of 2023 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 water, electric and natural gas systems.

During the three months ended December 31, 2023, the Renewable Energy Group made capital expenditures of $32.6 million as compared to $103.4 million during the same period in 2022. The Renewable Energy Group's investments during the fourth quarter of 2023 were primarily related to the development and/or construction of various projects and ongoing maintenance capital at existing operating sites.

2023 Annual Plant and Equipment Expenditures

During the twelve months ended December 31, 2023, the Regulated Services Group incurred capital expenditures of $742.0 million as compared to $1,594.9 million during the same period in 2022. The Regulated Services Group's investments in 2023 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. The Regulated Services Group's investments in 2022 included $609.0 million for the acquisition of Liberty Utilities (New York Water) Corp. (formerly New York American Water Company Inc.).

During the twelve months ended December 31, 2023, the Renewable Energy Group incurred capital expenditures of $320.3 million as compared to $176.6 million during the same period in 2022. The Renewable Energy Group's investments in 2023 were primarily related to the acquisition of the previously unowned portion of the Deerfield II Wind Facility and the development and/or construction of various projects and ongoing sustaining capital at existing operating sites.

Algonquin Power & Utilities Corp. - Management Discussion & Analysis 41

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, 2023:

	As at December 31, 2023											As at December 31, 2022
(all dollar amounts in $ millions)	Corporate			Regulated Services Group			Renewable Energy Group			Total		Total
Revolving and term credit facilities	$	1,075.0	1	$	2,387.0	2	$	1,100.0	3	$	4,562.0	$	4,513.3
Funds drawn on facilities / commercial paper issued	(779.1)			(1,851.2)			(262.6)			(2,892.9)		(1,532.5)
Letters of credit issued	(37.9)			(39.2)			(392.0)			(469.1)		(465.2)
Liquidity available under the facilities	258.0			496.6			445.4			1,200.0		2,515.6
Undrawn portion of uncommitted letter of credit facilities	(39.5)			—			(214.6)			(254.1)		(226.9)
Cash on hand										56.1		57.6
Total Liquidity and Capital Reserves	$	218.5		$	496.6		$	230.8		$	1,002.0	$	2,346.3
1 Includes a $75 million uncommitted standalone letter of credit facility.
2 Includes $176.5 million fully drawn term facilities of Suralis and BELCO as at December 31, 2023 ($163.3 million as at December 31, 2022).
3 Includes $600 million of uncommitted standalone letter of credit facilities.

Corporate

On March 31, 2023, the Company's senior unsecured revolving credit facility (the "Corporate Credit Facility") was amended and restated to increase the borrowing capacity from $500.0 million to $1.0 billion with a new maturity date of March 31, 2028. As at December 31, 2023, the Corporate Credit Facility had $779.1 million drawn and had $2.4 million of outstanding letters of credit.

On March 31, 2023, the Company entered into a new $75.0 million uncommitted bi-lateral credit facility. On June 1, 2023, the Company terminated its former $50.0 million uncommitted bi-lateral credit facility. As at December 31, 2023, the Company had issued $35.5 million of letters of credit from its $75.0 million uncommitted letter of credit facility.

Regulated Services Group

As at December 31, 2023, the Regulated Services Group's $1.0 billion senior unsecured revolving credit facility (the "Long-Term Regulated Services Credit Facility") had $371.0 million drawn and had $39.2 million of outstanding letters of credit. The Long-Term Regulated Services Credit Facility matures on April 29, 2027. As at December 31, 2023, the Regulated Services Group had $481.7 million of commercial paper issued and outstanding. On October 27, 2023, the Company extended the maturity date of the Regulated Services Group's $500.0 million senior unsecured revolving credit facility (the "Short-Term Regulated Services Credit Facility") from February 28, 2024 to October 25, 2024. As at December 31, 2023, the Short-Term Regulated Services Credit Facility had $125.0 million drawn and no outstanding letters of credit.

As at December 31, 2023, the Regulated Services Group's $75.0 million senior unsecured revolving credit facility (the "Bermuda Credit Facility") had $75.0 million drawn. Subsequent to the quarter end, on January 29, 2024, the Company amended the Bermuda Credit Facility, increasing the limit by $25 million to $100 million.

As at December 31, 2023, the Regulated Services Group's $25.0 million senior unsecured bilateral revolving credit facility (the "Bermuda Working Capital Facility") had $11.5 million drawn.

Algonquin Power & Utilities Corp. - Management Discussion & Analysis 42

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 a new maturity date of November 29, 2023. On April 25, 2023, the Company elected to terminate the remaining undrawn amount of $489.6 million. On October 27, 2023, the Company extended the maturity date of the Regulated Services Delayed Draw Term Facility from November 29, 2023 to October 25, 2024. As at December 31, 2023, the Regulated Services Delayed Draw Term Facility had $610.4 million drawn in connection with the acquisition of Liberty NY Water.

Renewable Energy Group

As at December 31, 2023, the Renewable Energy Group's $500.0 million senior unsecured syndicated revolving credit facility (the "Renewable Energy Credit Facility") had $262.6 million drawn and had $6.6 million in outstanding letters of credit. The Renewable Energy Credit Facility matures on July 22, 2027.

As at December 31, 2023, the Renewable Energy Group's bank lines consisted of $600.0 million letter of credit facilities (the "Renewable Energy LC Facilities"), including a $250.0 million uncommitted bilateral letter of credit facility and a $350.0 million uncommitted letter of credit facility. As at December 31, 2023, the Renewable Energy LC Facilities had $385.4 million in outstanding letters of credit.

Long-Term Debt

On March 13, 2023, the Company repaid a $15.0 million senior unsecured note on its maturity.

On July 31, 2023, the Company repaid a $75.0 million senior unsecured note on its maturity.

On November 1, 2023, the Company repaid a $5.0 million senior unsecured note on its maturity.

On November 6, 2023, the Company redeemed all $287.5 million of its 2018 Subordinated Notes at a redemption price equal to 100% of the principal amount, together with accrued and unpaid interest.

Issuance of $850 Million of Senior Unsecured Notes

On January 12, 2024, Liberty Utilities completed the Senior note Offering of $500 million aggregate principal amount of 5.577% senior notes due January 31, 2029; (the "2029 Notes") and $350 million aggregate principal amount of 5.869% senior notes due January 31, 2034 (the "2034 Notes" and, together with the 2029 Notes, the "Senior Notes"). The Senior Notes are unsecured and unsubordinated obligations of Liberty Utilities and rank equally with all of Liberty Utilities' existing and future unsecured and unsubordinated indebtedness and senior in right of payment to any existing and future Liberty Utilities subordinated indebtedness. The 2029 Notes were priced at an issue price of 99.996% of their face value and the 2034 Notes were priced at an issue price of 99.995% of their face value. Liberty Utilities used the net proceeds from the sale of the Senior Notes to repay indebtedness.

Issuance of $305.5 Million of Securitized Utility Tariff Bonds

On January 30, 2024, Empire District Bondco, LLC, a wholly owned subsidiary of The Empire District Electric Company, completed an offering of Securitization Bonds comprised of approximately $180.5 million of aggregate principal amount of 4.943% Securitized Utility Tariff Bonds with a maturity date of January 1, 2035 and $125.0 million aggregate principal amount of 5.091% Securitized Utility Tariff Bonds with a maturity date of January 1, 2039, to recover previously incurred qualified extraordinary costs associated with the Midwest Extreme Weather Event and energy transition costs related to the retirement of the Asbury generating plant. The principal asset securing the Securitization Bonds is the securitized utility tariff property.

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 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 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 "Subordinated Notes"). The following table summarizes the expected use of the net proceeds from the offerings of the Subordinated Notes compared to the actual use of such net proceeds:

Algonquin Power & Utilities Corp. - Management Discussion & Analysis 43

Expected Use of Net Proceeds

Actual Use of Net Proceeds

As disclosed in the Company’s prospectus supplements dated January 12, 2022 relating to the offerings of the Subordinated Notes, the Company previously expected that the net proceeds of the offerings of the Subordinated Notes would be used to partially finance the proposed acquisition of Kentucky Power Company and AEP Kentucky Transmission Company, Inc. (the “Kentucky Power Acquisition”); provided that, in the “short-term”, prior to the closing of the Kentucky Power Acquisition, the Company expected to use the net proceeds to reduce indebtedness as follows: (i) approximately $385.0 million to the Corporate Credit Facility; (ii) approximately $40.0 million to the Renewable Energy Credit Facility; (iii) approximately $415.0 million of commercial paper issued by Liberty Utilities; and (iv) approximately $219.9 million to the Long-Term Regulated Services Credit Facility.

As a result of the Kentucky Power Transaction Termination, the Company’s actual use of the net proceeds from the offerings of the Subordinated Notes is the reduction of indebtedness in such amounts as previously disclosed as the "short-term" use of the proceeds.

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 has a rating of BBB from S&P, BBB+ from Fitch and Baa2 from 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. The fixed-rate securitized utility tariff bonds (series 2024-A) issued by Empire District Bondco, LLC have a rating of AAA (sf) from S&P and Moody’s.

In April 2023, following the announcement of the Kentucky Power Transaction Termination, each of DBRS, Fitch, S&P and Moody’s made announcements regarding the credit ratings of the Corporation and its subsidiaries. DBRS and Fitch both affirmed their ratings and stable outlook on the Corporation and its subsidiaries, S&P affirmed its ratings and revised its outlooks to stable from negative on the Corporation and its subsidiaries and Moody’s affirmed its ratings and stable outlooks on Liberty Utilities and Liberty GP.

In May 2023, following the announcement of the Strategic Review, S&P placed APCo on credit watch with negative implications. APCo is the parent company for the U.S. and Canadian generating assets under the Renewable Energy Group. In August 2023, following the conclusion of the Strategic Review and the Company’s announcement that it will pursue the sale of its renewable energy business, S&P and Fitch made announcements regarding the credit ratings of the Corporation and its subsidiaries. S&P affirmed its ratings on AQN and its regulated utility subsidiaries and revised the outlook on APCo from credit watch with negative implications to developing. Fitch affirmed the ratings of AQN and placed APCo on rating watch evolving. Both S&P and Fitch expect to resolve their respective rating watch on APCo once more details are known on the transaction.

Algonquin Power & Utilities Corp. - Management Discussion & Analysis 44

Contractual Obligations

Information concerning contractual obligations as of December 31, 2023 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	$	8,537.7	$	621.9	$	1,333.8	$	2,100.0	$	4,482.0
Advances in aid of construction	88.1		3.6		—		—		84.5
Interest on long-term debt obligations2	4,910.3		391.5		602.8		420.0		3,496.0
Purchase obligations	765.3		765.3		—		—		—
Environmental obligations	46.2		3.1		22.6		1.8		18.7
Derivative financial instruments:
Cross currency interest rate swaps	16.4		2.4		4.2		0.1		9.7
Interest rate swaps	11.8		11.8		—		—		—
Energy derivative and commodity contracts	76.3		14.3		29.3		20.6		12.1
Purchased power	256.6		55.3		46.1		25.3		129.9
Gas delivery, service and supply agreements	454.6		121.2		114.6		64.0		154.8
Service agreements	557.7		73.7		118.5		106.0		259.5
Capital projects	5.6		5.6		—		—		—
Land easements	614.0		16.4		30.3		31.1		536.2
Contract adjustment payments on equity units	39.6		39.6		—		—		—
Other obligations	282.1		29.4		2.9		2.3		247.5
Total Obligations3	$	16,662.3	$	2,155.1	$	2,305.1	$	2,771.2	$	9,430.9

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 2079 and 2082, respectively. However, the Company currently anticipates repaying such notes in advance of maturity upon exercise of the Company’s redemption rights in accordance with the terms of the applicable indenture.
3	Excludes performance guarantees and other commitments on behalf of variable interest entities. See Note 8 in the annual consolidated financial statements.

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 6, 2024, AQN had 689,436,570 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 common 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 March 7, 2024, AQN had outstanding:

•4,800,000 Cumulative Rate Reset Preferred Shares, Series A, yielding 6.576% annually for the five-year period ending on December 31, 2028: and

•4,000,000 Cumulative Rate Reset Preferred Shares, Series D, 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 7, 2024, 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 by no later than 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.

Algonquin Power & Utilities Corp. - Management Discussion & Analysis 45

During the year ended December 31, 2023, 100 Series C preferred shares of AQN that had previously been issued in exchange for 100 Class B limited partnership units of St. Leon Wind Energy LP were redeemed for $14.5 million, and a loss of $2.4 million related to the redemption has been recognized.

Declaration of 2024 First Quarter Dividend of $0.1085 (C$0.1468) 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 2024 dividend of $0.1085 per common share payable on April 15, 2024 to shareholders of record on March 29, 2024.

The Canadian dollar equivalent for the first quarter 2024 dividend is C$0.1468 per common share.

The previous four quarter U.S. and Canadian dollar equivalent dividends per common share have been as follows:

	Q2 2023		Q3 2023		Q4 2023		Q1 2024		Total
U.S. dollar dividend	$	0.1085	$	0.1085	$	0.1085	$	0.1085	$0.4340
Canadian dollar equivalent	$	0.1453	$	0.1460	$	0.1497	$	0.1468	$0.5878

At-The-Market Equity Program

On August 15, 2022, AQN re-established an at-the-market equity program (“ATM Program”) that allowed 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 twelve months ended December 31, 2023, the Company did not issue any common shares under the ATM Program. The ATM Program terminated in accordance with its terms on December 19, 2023.

The Company has issued, since the inception of its initial ATM Program in 2019, a cumulative total of 36,815 common shares at an average price of $0.02 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

Effective March 16, 2023, AQN suspended its shareholder dividend reinvestment plan ("the Reinvestment Plan") for registered holders of common shares of AQN. Effective for the first quarter 2023 dividend (paid on April 14, 2023 to shareholders of record on March 31, 2023), shareholders participating in the Reinvestment Plan began 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.

As at December 31, 2023, 168,595,010 common shares representing approximately 24% of total common shares outstanding had been registered with the Reinvestment Plan. On January 13, 2023, 4,370,289 common shares were issued under the Reinvestment Plan in connection with the Company's fourth quarter 2022 dividend.

SHARE-BASED COMPENSATION PLANS

For the three and twelve months ended December 31, 2023, AQN recorded $3.5 million and $11.3 million in total share-based compensation expense, respectively, as compared to $3.9 million and $10.9 million for the same periods in 2022. 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, 2023, total unrecognized compensation costs related to non-vested share-based awards was $23.9 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’ vesting periods while ensuring that the cumulative amount of compensation cost recognized at least equals the value of the

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

vested portion of the award at that date. During the twelve months endedDecember 31, 2023, the Company granted 1,368,744 options to executives of the Company. The options allow for the purchase of common shares at a weighted average price of C$10.76, the market price of the underlying common share at the date of grant. One-third of the options vest on each of December 31, 2023, 2024 and 2025. The options may be exercised up to eight years following the date of grant. No stock options were exercised during the twelve months ended December 31, 2023.

As at December 31, 2023, a total of 2,667,725 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, 2023, the Company granted (including dividends) a combined total of 2,841,967 PSUs and RSUs to employees of the Company. The awards vest based on the terms of each agreement ranging from February 2023 to January 2025. During the twelve months endedDecember 31, 2023, the Company settled 922,883 PSUs, of which 451,003 PSUs were exchanged for common shares issued from treasury and 471,880 PSUs were settled at their cash value as payment for tax withholdings related to the settlement of the PSUs.

As at December 31, 2023, a combined total of 3,577,747 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. During the twelve months endedDecember 31, 2023, the Company issued 181,328 DSUs (including DSUs in lieu of dividends) to the non-employee directors of the Company. During the twelve months ended December 31, 2023, the Company settled 102,460 DSUs, of which 50,677 DSUs were exchanged for common shares issued from treasury and 51,783 DSUs were settled at their cash value as payment for tax withholdings related to the settlement of DSUs.

As at December 31, 2023, a total of 724,583 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, 2023, the Company settled 69,115 bonus RSUs, of which 31,455 were exchanged for common shares issued from treasury and 37,660 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, 2023, 77,981 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, 2023, the Company issued 752,582 common shares to employees under the ESPP.

As at December 31, 2023, a total of 3,110,532 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;

•To have available capital to finance capital expenditures sufficient to maintain existing assets;

Algonquin Power & Utilities Corp. - Management Discussion & Analysis 47

•To generate sufficient cash to fund sustainable dividends to shareholders as well as meet current tax and internal capital requirements; 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 have available funds to meet normal course capital and other expenditures.

RELATED PARTY TRANSACTIONS

Equity-method investments

The Company entered into a number of transactions with equity-method investees in 2023 and 2022 (see Note 16 in the annual consolidated financial statements).

The Company provides administrative and development services to its equity-method investees and is reimbursed for incurred costs. To that effect, the Company charged its equity-method investees1 $72.5 million in 2023, as compared to $63.9 million in 2022. Additionally, one of the equity-method investees (Liberty Development JV Inc., the Company’s former joint venture with funds managed by the Infrastructure and Power strategy of Ares Management, LLC for its non-regulated development platform) provides development services to the Company on specified projects, for which it earns a development fee that is capitalized by the Company, upon reaching certain milestones. During the year, the development fees charged to the Company were $27.9 million (2022 - $12.6 million). See Note 16 in the annual consolidated financial statements.

On July 5, 2023, the Company provided a $35 million non-interest-bearing loan to Liberty Development JV Inc. The joint venture used these funds to return equity to its shareholders through which the Company received $17.5 million.

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. (a joint venture between the Company and Ares), an equity-method investee of the Company. (see Note 16 in the annual consolidated financial statements). Redemption is not considered probable as at December 31, 2023. The preference share was used to finance a portion of the Company's investment in Atlantica. During the year ended December 31, 2023, the Company incurred non-controlling interest attributable to Liberty Development Energy Solutions B.V. of $25.9 million, as compared to $15.2 million during the same period in 2022, and recorded distributions of $25.4 million, for the year ended December 31, 2023 as compared to $13.8 million during the same period in 2022 (see Note 16 in the annual consolidated financial statements).

Liberty Development Energy Solutions B.V. has a secured credit facility in the amount of $306.5 million maturing on September 30, 2024. It is collateralized through a pledge of Atlantica ordinary shares. A collateral shortfall would occur if the net obligation as defined in the credit agreement would equal or exceed 50% of the market value of such Atlantica shares, in which case the lenders would have the right to sell Atlantica shares to eliminate the collateral shortfall. The Liberty Development Energy Solutions B.V. secured credit facility is repayable on demand if Atlantica ceases to be a public company or if certain other events are announced or completed that could restrict AY Holdings’ ability to sell or transfer its Atlantica ordinary shares.

On January 4, 2024, the Company purchased the remaining 50% of the equity of Liberty Development JV Inc. and Liberty Development Energy Solutions B.V. for $7.9 million. As a result, the redeemable non-controlling interest held by related party will be reclassified to long-term debt in 2024.

Non-controlling interest held by related party

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 and an interest in Algonquin (AY Holdco) B.V., a consolidated subsidiary of the Company, acquired by Liberty Development JV Inc. in November 2021 for $39.4 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, 2023, the Company recorded distributions of $17.1 million, as compared to $21.0 million during the same period in 2022.

1Primarily Liberty Development JV Inc. and its subsidiaries, Blue Hill Wind Energy Project Partnership and Red Lily Wind Energy Partnership.

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Transactions with Atlantica

On December 28, 2023, Liberty Development Spain, S.A., a wholly owned subsidiary of the Company entered into an agreement to sell its 100% equity interests in Liberty Jimena, S.L. and Liberty Caparacena, S.L., and its 80% equity interest in Liberty Infrastructuras, S.L. to Atlantica for a nominal amount. As a result, the Company recorded an impairment loss of $1.5 million. The transaction closed on January 23, 2024.

The above related party transactions have been recorded at the exchange amounts agreed to by the parties to the transactions.

ENTERPRISE RISK MANAGEMENT

The Corporation is subject to a number of risks and uncertainties, certain of which are described below. The risks discussed below are not intended to be 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, rules 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, reinterpretations of or application of existing laws, rules, orders or regulations, the imposition of new laws, rules, orders or regulations (including the power of eminent domain), and the taking of other action by governmental or regulatory authorities, including, but not limited to, revocation, lapse, limitation or non-renewal of utility franchises or other rights to provide utility services to existing or new customers, potential limitations on water rights used by utilities in providing service, actions to municipalize utility service areas or limitations on utility growth and/or expansions of service areas, any of which could adversely affect the 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 issuer 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 credit rating from S&P, a 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 issuer credit rating of BBB from S&P, a BBB issuer rating from Fitch and a Baa2 issuer rating from Moody’s. Debt issued by Liberty Utilities has a rating of BBB from S&P, BBB+ from Fitch and Baa2 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 a BBB issuer rating from DBRS. The fixed-rate securitized utility tariff bonds (series 2024-A) issued by Empire District Bondco, LLC have a rating of AAA (sf) from S&P and Moody’s. There can be no assurance that any of the current ratings of AQN or its subsidiaries 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.

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 any of 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 or its subsidiaries to post additional or replacement security under certain contracts and hedging arrangements, which could result in increased costs to the Company. 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.

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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.

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. The Corporation is pursuing a sale of its renewable energy business, which, if completed, is expected to impact the activities needed in order to maintain a BBB flat investment grade rating. APCo’s credit ratings may be subject to evaluation and/or downgrade by one or more notches (including to a sub-investment grade rating) in connection with the Company’s pursuit of a sale of its renewable energy business.

Capital Markets and Liquidity Risk

As at December 31, 2023, the Company had approximately $8,516.3 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, the proceeds of the proposed sale of the renewable energy business or from other potential future dispositions, 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 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 or maintain prior dividend levels; 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 no less favourable than the current terms, the Company's cash flows and 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, disposition 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

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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, dispositions and energy facilities, especially where project financing is being renewed or arranged.

As a result, fluctuations in interest rates, including the rate increases experienced in 2022 and 2023, could materially increase the Corporation’s financing costs, limit the Corporation’s options for financing or investment 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, 2023, approximately 85% 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 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. On September 29, 2023, the Company entered into a new interest rate cap agreement in the amount of $390 million for the period between January 15, 2024 and June 17, 2024.

Based on amounts outstanding as at December 31, 2023, 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 $779.1 million outstanding as at December 31, 2023. The Corporate Credit Facility has locked in $197.5 million of the variable rate until March 29, 2024, $245.0 million of the variable rate until April 5, 2024 and $30.0 million of the variable rate until June 28, 2024 through a six month interest election request. As a result, a 100 basis point change in the variable rate charged would impact interest expense by $3.1 million annually;

•the Long-Term Regulated Services Credit Facility is subject to a variable interest rate and had $371.0 million outstanding as at December 31, 2023. As a result, a 100 basis point change in the variable rate charged would impact interest expense by $3.7 million annually;

•the Short-Term Regulated Services Credit Facility is subject to a variable interest rate and had $125.0 million outstanding as at December 31, 2023. As a result, a 100 basis point change in the variable rate charged would impact interest expense by $1.3 million annually;

•the Regulated Services Delayed Draw Term Facility is subject to a variable interest rate and had $610.4 million outstanding as at December 31, 2023. The Regulated Services Group has locked in the variable rate until April 27, 2024 through an interest election request. As a result, a 100 basis point change in the variable rate charged would not impact interest expense;

•the Bermuda Credit Facility is subject to a variable interest rate and had $75.0 million outstanding as at December 31, 2023. As a result, a 100 basis point change in the variable rate charged would impact interest expense by $0.8 million annually;

•the Bermuda Working Capital Facility is subject to a variable interest rate and had $11.5 million outstanding as at December 31, 2023. As a result, a 100 basis point change in the variable rate charged would impact interest expense by $0.1 million annually;

•the Regulated Services Group's commercial paper program is subject to a variable interest rate and had $481.7 million outstanding as at December 31, 2023. As a result, a 100 basis point change in the variable rate charged would impact interest expense by $4.8 million annually;

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•the Renewable Energy Credit Facility is subject to a variable interest rate and had $262.6 million outstanding as at December 31, 2023. The Renewable Energy Credit Facility has locked in $120.0 million of the variable rate until June 28, 2024. As a result, a 100 basis point change in the variable rate charged would impact interest expense by $1.4 million annually; and

•term facilities at Suralis that are subject to variable interest rates had $115.6 million outstanding as at December 31, 2023. As a result, a 100 basis point change in the variable rate charged would impact interest expense by $1.2 million annually.

The term loan facility at BELCO is subject to variable interest rates. However, the Company separately entered into an interest swap agreement to hedge the risk associated with interest rate fluctuation.

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.

Tax Risk and Uncertainty

The Corporation is subject to income and other taxes primarily in the United States, Canada, Bermuda, and Chile, though it is subject to tax in other jurisdictions. Changes in tax laws or interpretations or applications thereof, which may or may not have a retroactive effect, in the jurisdictions in which the Corporation does business could adversely affect the Company's results from operations, returns to shareholders, and cash flows.

Pending tax law changes that may adversely impact the Corporation’s effective tax rate (and hence, financial results) or result in additional cash taxes include, but are not limited to:

•legislation proposed in Canada to generally limit the deductibility of interest and financing expenses to 30% of tax EBITDA. If enacted in the form proposed, this legislation will generally apply to taxation years of the Corporation beginning on or after October 1, 2023; and

•implementation of global minimum tax rules in the various jurisdictions in which the Corporation operates pursuant to the Organization for Economic Development’s initiative to prevent perceived base erosion and profit shifting. Legislation has been proposed in Canada pursuant to this initiative which, if enacted in the form proposed, will generally be applicable for fiscal years of a “qualifying MNE group” (as defined in such proposed legislation) beginning on or after December 31, 2023.

The proposed rules are complex and once enacted will be subject to the Corporation’s judgment in its application until further guidance is available.

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 or elimination of incentives may be insufficient to

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support continued development or may result in substantially reduced financial benefits from facilities that are completed. 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 11% of total Company revenues with the majority earned from large investment-grade customers having a credit rating of Baa2 or better by Moody's, or BBB or higher by S&P and Fitch or BBB or higher by DBRS.

The remaining revenue of the Company is primarily earned by the Regulated Services Group.

The credit exposure attributed to the Regulated Services Group's accounts receivable balances at the water and wastewater distribution systems total $83.6 million which is spread over approximately 572,000 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 $126.6 million, while electric distribution systems accounts receivable balances related to the electric utilities total $150.8 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 $338 dollars and $488 dollars respectively. Counterparty performance risk also exists in the natural gas distribution utilities 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 and water industries or in the general economy, 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, service 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. Losses associated with equipment failure, defects, design flaws or other issues resulting from counterparty non-performance may not be covered by warranties or insurance.

Market Price Risk

The Renewable Energy Group enters into long-term offtake contracts at project inception. Offtake contracts are either unit contingent (volumes are contingent on energy produced and price is fixed) or fixed for floating financial swaps (fixed contract volumes and pricing). These offtake contracts can be exposed to market settlements related to transmission congestion, hedge shortfall and uncontracted generation prices.

Basis risk exists on both unit contingent and fixed volume financial swaps if the offtake contract settles at a different point (i.e. hub settlement point vs. the point of injection to the system or the asset price node). In an effort to mitigate basis risk, the Company has from time to time entered into additional financial contracts to fix the basis price.

There is a risk that the Renewable Energy Group is not able to generate the specified amount of power at the specified time resulting in production shortfalls which can impact the settlement of fixed volume financial swaps. This risk is known as "hedge shortfall". A fixed volume financial swap pays the Renewable Energy Group a fixed price for a fixed volume. When the energy produced is less than the fixed volume, the asset pays the settled market price (i.e. price node value) to the offtaker. In an effort to mitigate the risk of production shortfalls under hedges, the Renewable Energy Group has from time to time sized the hedges to cover less than 100% of the anticipated production, thereby reducing the risk of not producing the minimum hedge quantities. 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.

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Merchant (uncontracted) generation may increase earnings volatility. In a rising price environment, merchant generation generally results in higher earnings than a fully contracted portfolio. In a falling price environment, merchant generation generally results in lower earnings than a fully contracted portfolio. The Renewable Energy Group is subject to the risk of impairment to its renewable power generation assets associated with potential declines in long-term forecasted power prices if the forecasted power prices are materially lower than current contracted prices for the period following the expiration of the offtake agreement. The market price risk for the Renewable Energy Group is primarily within the ERCOT, PJM, and MISO markets.

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

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commodity price fluctuations, the Midstates Gas System has implemented a commodity hedging program, consistent with 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 sells capacity (Reserve Adequacy) in the California market which carries dispatch obligations to CAISO. Sanger is dispatched in the CAISO energy market based on the price of its energy offers submitted to CAISO. These energy offers are priced using Sanger’s cost of production which includes fuel costs, fuel energy required (Heat rate), variable operating costs and environmental offsets. As the fuel price changes, Sanger’s cost of production and CAISO energy market offers are adjusted accordingly thereby insulating Sanger from fuel price exposure.

OPERATIONAL RISK MANAGEMENT

Dispositions, including Risks Relating to the Planned Sale of the Company's Renewable Energy Business

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. 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. A disposition may also result in liabilities to the Corporation, including as a result of any post-closing indemnities or purchase price adjustments. 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, including one or more potential issuances of equity, 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.

On August 10, 2023, the Company announced its pursuit of a sale of its renewable energy business. There can be no assurance about the outcome of this sale process, the specific assets that will be sold (if any), that any specific transaction will be identified or consummated, or that any such transaction will achieve any expected result or benefit. Divesting any or all of the assets comprising the Company’s renewable energy business involves a number of risks and uncertainties, including complexities involved in separating assets that may be sold from assets the Company will retain, the need to

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obtain regulatory approvals and other third-party consents, which could, among other things, disrupt customer and supplier relationships, and the fact that the Company may be subject to additional tax obligations or loss of certain tax benefits. If the Company disposes of all or a portion of the assets comprising the Company’s renewable energy business, it may not be able to successfully cause a buyer to assume the liabilities related to such assets or, even if such liabilities are assumed, the Company may have difficulties enforcing its rights, contractual or otherwise, against the buyer. The Company may be required to provide transitional services to the buyer for a period of time following closing of a transaction, and the Company may retain obligations related to divested assets, and may be subject to potential liabilities that arise because of the disposition or the subsequent breaches of obligations or duties by the buyer. There are factors that could delay, prevent or otherwise adversely affect the planned sale, including but not limited to market conditions or delays in obtaining necessary counterparty approvals, regulatory approvals or clearances. In addition, whether or not any specific transaction is identified, pursued and/or consummated, the process could cause disruptions in the business of the Company by diverting the attention of the Board and management and diverting other resources (including costs) towards such process and the preparation of the Company to pursue and consummate a transaction. The process could also impact the Company’s relationships with employees, including by increasing employee departures and turnover, could give rise to disputes with potential buyers and could result in accounting changes, restructuring and other disposition charges, as well as potential impairment charges or losses. The sale of any or all of the assets comprising the Company's renewable energy business could negatively impact the Company’s profitability, financial results and dividends because of losses that may result from such a sale, the loss of revenues or a decrease in cash flows or cash available for distribution. In addition, APCo may be subject to one or more credit rating downgrades as a result of the Corporation’s pursuit of its renewable energy business. Following a sale of any or all of the assets comprising the Company's renewable energy business, the Company would also have less diversity in the asset mix of its business and in the markets it serves. Any or all of these risks could impact the Company’s financial results and business reputation.

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 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, contamination of water or equipment in a in drinking water distribution system could result in severe injury, illness or death to those who drink the impacted 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 have occurred, and may in the future occur, within the Regulated Services Group’s electric distribution service territories, including, without limitation, in California and other parts of the United States in which the Corporation operates, such as the Mountain View fire that occurred on November 17, 2020 within the CalPeco Electric System’s service territory in California. 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 (regardless of whether it is at fault or negligent), 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

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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 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 utilities 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. As the Company is in the process of updating its technology infrastructure systems, there is a risk that financial data required for rate filings could be difficult to produce or deemed unreliable for ratemaking purposes, thus increasing the risk of disallowance and/or regulatory lag. 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.

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 and other offtake agreements, 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 related to 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

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U.S., tariffs have been imposed in recent years on imports of solar panels, solar cells, 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.

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 bribery and 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 had 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.

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The Company’s international activities and operations 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 less than 100% and/or partners in certain projects and facilities. As a result, the Company may not operate or control all or any decision-making in respect of 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 transactions and decisions, including among others, the sale of the Corporation’s renewable energy business and 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, construct or operate 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 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 $1,044.5 million as of December 31, 2023.

Please refer to Note 8 in the annual consolidated financial statements for a description of the Company's Long-Term Investments and Notes Receivable.

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

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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 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 and water and wastewater facilities, and currently has a pipeline of renewable energy generation and storage projects in development or construction, as well as the development and construction of transmission and distribution assets and other complementary projects. There can be no assurance that the Corporation will be able to identify attractive acquisition or development candidates 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

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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 investors or purchasers of tax credits, the participation of which depends upon the 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 21 lawsuits that name certain subsidiaries of the Company as defendants in connection with the Mountain View Fire, as well as a non-litigation claim brought by the U.S. Department of Agriculture seeking reimbursement for alleged fire suppression costs and a notice from the U.S. Bureau of Land Management seeking damages for the alleged burning of public lands without authorization. Fourteen 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 14 lawsuits also alleges the wrongful death of an individual and various subrogation claims on behalf of insurance companies). On March 6, 2024, a trial commenced in Los Angeles County Superior Court on four bellwether cases with respect to inverse condemnation liability only. If the Company’s subsidiaries were found liable in those cases, the damages, if any, would not be determined at this trial. In another lawsuit, County of Mono, Antelope Valley Fire Protection District, 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 six other lawsuits, insurance companies allege inverse condemnation and negligence and seek recovery of amounts paid and to be paid to their insureds. The likelihood of success in these lawsuits is uncertain. Liberty CalPeco intends to vigorously defend them. In 2023, Liberty CalPeco accrued estimated losses of $66 million for claims related to the Mountain View Fire, against which Liberty CalPeco has recorded expected recoveries from insurance of $66 million. The resulting net charge to earnings was $nil. The estimate of losses is subject to change as additional information becomes available. The actual amount of losses may be higher or lower than these estimates. While the Company may incur a material loss in excess of the amount accrued, the Company cannot estimate the upper end of the range of reasonably possible losses that may be incurred. 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

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

$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, which is proceeding before the Court of Appeals.

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 and 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 geopolitical tension, and any associated sanctions imposed or actions taken by the United States, Canada or other countries or retaliatory measures by nation states or other actors), 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 social engineering and general purpose or industry specific malware or ransomware 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 or other geopolitical conflicts) may affect operations of the Company in unpredictable ways, including 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,

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

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 includes customer billing, enterprise resource planning systems and asset management systems. The implementation of these systems is being managed by a dedicated team. Following pilot implementations, deployment began in 2022 and has occurred in a phased approach that is expected to be completed in 2024. The implementation of such technology systems requires 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.

Initiatives designed to reduce greenhouse gas emissions and control or limit the effects of climate change have 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.

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 potential 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 may not be economically viable or may not otherwise be 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

Algonquin Power & Utilities Corp. - Management Discussion & Analysis 63

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, wildfires, 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, 2023:

(all dollar amounts in $ millions except per share information)	1st Quarter 2023		2nd Quarter 2023		3rd Quarter 2023		4th Quarter 2023
Revenue	$	778.6	$	627.9	$	624.6	$	666.9
Net earnings (loss) attributable to shareholders	270.1		(253.2)		(174.5)		186.3
Net earnings (loss) per share	0.39		(0.37)		(0.26)		0.27
Diluted net earnings (loss) per share	0.39		(0.37)		(0.26)		0.27
Adjusted Net Earnings1	119.9		56.2		80.5		115.5
Adjusted Net Earnings per common share1	0.17		0.08		0.11		0.16
Adjusted EBITDA1	341.0		277.7		282.5		334.3
Total assets	17,927.1		17,968.7		17,982.8		18,374.0
Long-term debt2	7,849.2		8,083.4		8,367.3		8,516.3
Dividend declared per common share	$	0.11	$	0.11	$	0.11	$	0.11
	1st Quarter 2022		2nd Quarter 2022		3rd Quarter 2022		4th Quarter 2022
Revenue	$	733.2	$	619.4	$	664.4	$	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	140.0		109.6		73.5		97.6
Adjusted Net Earnings per common share1	0.20		0.16		0.11		0.14
Adjusted EBITDA1	329.3		289.2		276.1		295.5
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

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.

Quarterly revenues have fluctuated between $619.4 million and $778.6 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 $253.2 million and earnings of $270.1 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.

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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, 2023 and 2022 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)	2023		2022
Revenue	$	1,099.9	$	1,102.0
Profit (loss) for the year	36.4		(2.1)
Total non-current assets	7,732.2		8,069.2
Total current assets	982.2		1,031.7
Total non-current liabilities	6,517.7		6,792.9
Total current liabilities	607.8		519.0

DISCLOSURE CONTROLS AND PROCEDURES

AQN's management carried out an evaluation as of December 31, 2023, 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, 2023, 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 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.

Management assessed the effectiveness of the Company's internal control over financial reporting as of December 31, 2023, 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, 2023 to provide reasonable assurance regarding the reliability of financial reporting and the preparation of consolidated financial statements for external reporting purposes in accordance with U.S. GAAP. Management reviewed the results of its assessment with the Audit & Finance Committee of the Board.

Changes in Internal Controls over Financial Reporting

For the twelve months ended December 31, 2023, there has been no change in the Company’s internal controls over financial reporting that has materially affected, or is reasonably likely to materially affect, the Company’s internal controls 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.

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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 & Finance Committee of the Board.

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.

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 2023 and 2022, 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.

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

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.

The U.S. entities in the Renewable Energy Group continue to be in an overall deferred tax asset position as at December 31, 2023. In the course of assessing the U.S. deferred tax assets in the Renewable Energy Group, management concluded, similar to 2022, that it was not probable that the U.S. business of the Renewable Energy Group would generate sufficient taxable income to realize the benefit of the deferred tax assets of such group (with the exception of certain transferable tax credits). Management’s conclusion is based on the balance of all available positive and negative evidence applicable to the Renewable Energy Group. 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.

Management’s assessment of the deferred tax asset in Canada supports that it is probable that the benefit of such assets will be realized. While the Canadian entities are operationally profitable, the Canadian entities as a whole, are in a cumulative 3-year loss position. Management has evaluated all available positive and negative evidence applicable to the entities in Canada and has concluded that it is probable that the Canadian businesses will make sufficient taxable profit to allow them to utilize their available tax attributes prior to their expiry.

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 Suralis.

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 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.

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

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, 2023 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, 2023 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 2023 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.

	2023 Pension Plans				2023 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		(56.7)		(1.4)		(22.6)		(1.5)
1% decrease		67.9		2.5		27.7		1.7
Future compensation rate
1% increase		1.9		1.2		—		—
1% decrease		(1.7)		(1.1)		—		—
Expected return on plan assets
1% increase		—		(5.5)		—		(1.5)
1% decrease		—		5.5		—		1.5
Health care trend
1% increase		—		—		25.6		3.4
1% decrease		—		—		(21.2)		(2.8)

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.

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Consolidated Financial Statements of

Algonquin Power & Utilities Corp.

For the years ended December 31, 2023 and 2022

Consolidated Financial Statements 69

MANAGEMENT’S REPORT

Financial Reporting

The accompanying consolidated financial statements and management discussion and analysis (“MD&A”) are the responsibility of management and have been approved by the Board of Directors.

The consolidated financial statements have been prepared by management in accordance with U.S. generally accepted accounting principles. Financial statements by nature include amounts based upon estimates and judgments. When alternative accounting methods exist, management has chosen those it deems most appropriate in the circumstances.

The Board of Directors and its committees are responsible for all aspects related to governance of the Company. The Audit & Finance Committee of the Board of Directors, composed of directors who are unrelated and independent, has a specific responsibility to oversee management’s efforts to fulfill its responsibilities for financial reporting and internal controls related thereto. The Committee meets with management and independent auditors to review the consolidated financial statements and the internal controls as they relate to financial reporting. The Audit & Finance Committee reports its findings to the Board of Directors for its consideration in approving the consolidated financial statements for issuance to the shareholders.

Internal Control over Financial Reporting

Management is also responsible for establishing and maintaining adequate internal control over financial reporting. The Company’s internal control over financial reporting is a process designed to provide reasonable assurance regarding the reliability of financial reporting and the preparation of consolidated financial statements for external purposes in accordance with generally accepted accounting principles.

Management assessed the effectiveness of the Company’s internal control over financial reporting as of December 31, 2023, based on the framework established in Internal Control – Integrated Framework (2013) issued by the Committee of Sponsoring Organizations of the Treadway Commission (COSO). Based on this assessment, management concluded that the Company maintained effective internal control over financial reporting as of December 31, 2023. Ernst & Young LLP, the independent registered public accounting firm that audited the accompanying consolidated financial statements has issued its attestation report on the Company’s internal control over financial reporting,

March 8, 2024

/s/ Chris Huskilson	/s/ Darren Myers
Interim Chief Executive Officer	Chief Financial Officer

Consolidated Financial Statements 70

REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM

To the Shareholders and the Board of Directors of Algonquin Power & Utilities Corp.

Opinion on the Consolidated Financial Statements

We have audited the accompanying consolidated balance sheets of Algonquin Power & Utilities Corp. (the “Company”), as of December 31, 2023 and 2022, the related consolidated statements of operations, comprehensive income (loss), equity and cash flows for the years then ended, and the related notes (collectively referred to as the “consolidated financial statements”). In our opinion, the consolidated financial statements present fairly, in all material respects, the financial position of the Company as of December 31, 2023 and 2022, and the results of its operations and its cash flows for the years then ended in conformity with U.S. generally accepted accounting principles.

We also have audited, in accordance with the standards of the Public Company Accounting Oversight Board (United States) (“PCAOB”), the Company’s internal control over financial reporting as of December 31, 2023, based on the criteria established in Internal Control – Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission (2013 framework), and our report dated March 8, 2024 expressed an unqualified opinion thereon.

Basis for Opinion

These financial statements are the responsibility of the Company‘s management. Our responsibility is to express an opinion on the Company‘s financial statements based on our audits. We are a public accounting firm registered with the PCAOB and are required to be independent with respect to the Company in accordance with the US federal securities laws and the applicable rules and regulations of the Securities and Exchange Commission and the PCAOB.

We conducted our audits in accordance with the standards of the PCAOB. Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement, whether due to error or fraud.

Our audits included performing procedures to assess the risks of material misstatement of the financial statements, whether due to error or fraud, and performing procedures that respond to those risks. Such procedures include examining, on a test basis, evidence regarding the amounts and disclosures in the financial statements. Our audits also included evaluating the accounting principles used and significant estimates made by management, as well as evaluating the overall presentation of the financial statements. We believe that our audits provide a reasonable basis for our opinion.

Critical Audit Matter

The critical audit matter communicated below is a matter arising from the current period audit of the financial statements that is communicated or required to be communicated to the Audit & Finance Committee and that: (1) relates to accounts or disclosures that are material to the financial statements and (2) involved our especially challenging, subjective, or complex judgments. The communication of the critical audit matter does not alter in any way our opinion on the consolidated financial statements, taken as a whole, and we are not, by communicating the critical audit matter below, providing a separate opinion on the critical audit matter or on the accounts or disclosures to which it relates.

Consolidated Financial Statements 71

	Regulatory assets and liabilities—Recovery of costs through rate regulation
Description of the Matter	As described in Note 7 to the consolidated financial statements, the Company has approximately $1.33 billion in regulatory assets and approximately $734.30 million in regulatory liabilities that are subject to regulation by the public utility commissions of the regions in which they operate. Rates are determined under cost-of-service regulation. The regulation of rates is premised on the full recovery of prudently incurred costs and a reasonable rate of return on assets or common shareholder’s equity. Regulatory decisions can have an impact on the timely recovery of costs and the approved returns. The recoverability of such costs through rate-regulation impacts multiple financial statement line items and disclosures, including property, plant, and equipment, regulatory assets and liabilities, derivative instruments, pension and other post-employment benefit obligation, regulated electricity, gas and water distribution revenues and the corresponding expenses, income tax expense, and depreciation and amortization expense. Although the Company expects to recover its costs from customers through rates, there is a risk that the respective regulator will not approve full recovery of the costs incurred. Auditing the recoverability of these costs through rates is complex and highly judgmental due to the significant judgments and probability assessments made by the Company to support its accounting and disclosure for regulatory matters when final regulatory decisions or orders have not yet been obtained or when regulatory formulas are complex. There is also subjectivity involved in assessing the potential impact of future regulatory decisions on the financial statements. The Company’s judgments include evaluating the probability of recovery of and recovery on costs incurred, or probability of refund to customers through future rates.
How We Addressed the Matter in Our Audit	We obtained an understanding, evaluated the design and tested the operating effectiveness of controls over the Company’s evaluation of the likelihood of recovery of regulatory assets and refund of regulatory liabilities, including management’s controls over the initial recognition and the monitoring and evaluation of regulatory developments that may affect the likelihood of recovering costs in future rates, a refund, or future changes in rates. We performed audit procedures that included, amongst others, evaluating the Company’s assessment of the probability of future recovery for regulatory assets and refund of regulatory liabilities, by comparison to the relevant regulatory orders, filings and correspondence, and other publicly available information including past precedents. For regulatory matters for which regulatory decisions or orders have not yet been obtained, we inspected the Company’s filings for any evidence that might contradict the Company’s assertions, and reviewed other regulatory orders, filings and correspondence for other entities within the same or similar jurisdictions to assess the likelihood of recovery in future rates based on the respective regulator’s treatment of similar costs under similar circumstances. We evaluated the Company’s analysis and compared that analysis with letters from legal counsel, when appropriate, regarding cost recoveries or future changes in rates. We assessed the methodology and mathematical accuracy of the Company’s calculations of regulatory asset and liability balances based on provisions and formulas outlined in rate orders and other correspondence with regulators.

/s/ Ernst & Young LLP        

Chartered Professional Accountants

Licensed Public Accountants

We have served as the Company's auditor since 2013.

Toronto, Canada

March 8, 2024

Consolidated Financial Statements 72

REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM

To the Shareholders and the Board of Directors of Algonquin Power & Utilities Corp.

Opinion on Internal Control over Financial Reporting

We have audited Algonquin Power & Utilities Corp.’s internal control over financial reporting as of December 31, 2023, based on criteria established in Internal Control—Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission (2013 framework) (the “COSO criteria”). In our opinion, Algonquin Power & Utilities Corp. (the “Company”) maintained, in all material respects, effective internal control over financial reporting as of December 31, 2023, based on the COSO criteria.

We also have audited, in accordance with the standards of the Public Accounting Oversight Board (United States) (“PCAOB”), the consolidated balance sheets of the Company as of December 31, 2023, and 2022, the related consolidated statements of operations, comprehensive income (loss), equity and cash flows for the years then ended, and the related notes, and our report dated March 8, 2024, expressed an unqualified opinion thereon.

Basis for Opinion

The Company’s management is responsible for maintaining effective internal control over financial reporting and for its assessment of the effectiveness of internal control over financial reporting included in the Management Report on Internal Controls over Financial Reporting section contained in the accompanying Management Discussion and Analysis. Our responsibility is to express an opinion on the Company’s internal control over financial reporting based on our audit. We are a public accounting firm registered with the PCAOB and are required to be independent with respect to the Company in accordance with the U.S. federal securities laws and the applicable rules and regulations of the Securities and Exchange Commission and the PCAOB.

We conducted our audit in accordance with the standards of the PCAOB. Those standards require that we plan and perform the audit to obtain reasonable assurance about whether effective internal control over financial reporting was maintained in all material respects.

Our audit included obtaining an understanding of internal control over financial reporting, assessing the risk that a material weakness exists, testing and evaluating the design and operating effectiveness of internal control based on the assessed risk, and performing such other procedures as we considered necessary in the circumstances. We believe that our audit provides a reasonable basis for our opinion.

Definition and Limitations of Internal Control Over Financial Reporting

A company’s internal control over financial reporting is a process designed to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles. A company’s internal control over financial reporting includes those policies and procedures that (1) pertain to the maintenance of records that, in reasonable detail, accurately and fairly reflect the transactions and dispositions of the assets of the company; (2) provide reasonable assurance that transactions are recorded as necessary to permit preparation of financial statements in accordance with generally accepted accounting principles, and that receipts and expenditures of the company are being made only in accordance with authorizations of management and directors of the company; and (3) provide reasonable assurance regarding prevention or timely detection of unauthorized acquisition, use, or disposition of the company’s assets that could have a material effect on the financial statements.

Because of its inherent limitations, internal control over financial reporting may not prevent or detect misstatements. Also, projections of any evaluation of effectiveness to future periods are subject to the risk that controls may become inadequate because of changes in conditions, or that the degree of compliance with the policies or procedures may deteriorate.

/s/ Ernst & Young LLP        

Chartered Professional Accountants

Licensed Public Accountants

Toronto, Canada

March 8, 2024

Consolidated Financial Statements 73

Algonquin Power & Utilities Corp.

Consolidated Statements of Operations

	Years ended
(thousands of U.S. dollars, except per share amounts)	December 31
	2023		2022
Revenue
Regulated electricity distribution	$	1,295,497	$	1,278,912
Regulated natural gas distribution	621,173		686,744
Regulated water reclamation and distribution	399,052		364,383
Non-regulated energy sales	296,314		350,797
Other revenue	85,979		84,177
	2,698,015		2,765,013
Expenses
Operating expenses	906,985		851,489
Regulated electricity purchased	429,760		465,570
Regulated natural gas purchased	267,122		340,792
Regulated water purchased	19,564		18,308
Non-regulated energy purchased	19,499		41,684
Administrative expenses	90,359		80,232
Depreciation and amortization	466,996		455,520
Asset impairment charge (notes 5, 8 and 16)	23,492		159,568
Loss on foreign exchange	8,359		13,833
	2,232,136		2,426,996
Gain on sale of renewable assets	—		64,028
Operating income	465,879		402,045
Interest expense (note 9)	(353,656)		(278,574)
Loss from long-term investments (note 8)	(124,974)		(483,385)
Other income (note 7)	41,410		18,179
Other net losses (note 19)	(132,889)		(21,391)
Pension and other post-employment non-service costs (note 10)	(19,939)		(10,950)
Gain on derivative financial instruments (note 24(b)(iv))	4,564		4,408
Loss before income taxes	(119,605)		(369,668)
Income tax recovery (expense) (note 18)
Current	9,740		(7,843)
Deferred	76,560		69,356
	86,300		61,513
Net loss	(33,305)		(308,155)
Net effect of non-controlling interests (note 17)
Non-controlling interests	87,901		111,323
Non-controlling interests held by related party	(25,922)		(15,157)
	$	61,979	$	96,166
Net earnings (loss) attributable to shareholders of Algonquin Power & Utilities Corp.	$	28,674	$	(211,989)
Series A Shares and Series D Shares dividend (note 15)	8,356		8,720
Net earnings (loss) attributable to common shareholders of Algonquin Power & Utilities Corp.	$	20,318	$	(220,709)
Basic and diluted net earnings (loss) per share (note 20)	$	0.03	$	(0.33)

See accompanying notes to consolidated financial statements

Consolidated Financial Statements 74

Algonquin Power & Utilities Corp.

Consolidated Statements of Comprehensive Income (Loss)

	Years ended
(thousands of U.S. dollars)	December 31
	2023		2022
Net loss	$	(33,305)	$	(308,155)
Other comprehensive income (loss) (“OCI”):
Foreign currency translation adjustment, net of tax recovery of $6,616 (2022 - tax expense $2,423), (notes 24(b)(iii) and 24(b)(iv))	(5,386)		(23,502)
Change in fair value of cash flow hedges, net of tax recovery of $1,885 (2022 - tax expense of $20,644), (note 24(b)(ii))	59,487		(94,295)
Change in pension and other post-employment benefits, net of tax expense of $1,612 (2022 - tax expense of $8,330), (note 10)	4,693		27,761
OCI, net of tax	58,794		(90,036)
Comprehensive income (loss)	25,489		(398,191)
Comprehensive loss attributable to the non-controlling interests	(60,962)		(97,816)
Comprehensive income (loss) attributable to shareholders of Algonquin Power & Utilities Corp.	$	86,451	$	(300,375)

See accompanying notes to consolidated financial statements

Consolidated Financial Statements 75

Algonquin Power & Utilities Corp.

Consolidated Balance Sheets

(thousands of U.S. dollars)
	December 31,		December 31,
	2023		2022
ASSETS
Current assets:
Cash and cash equivalents	$	56,142	$	57,623
Trade and other receivables, net (note 4)	524,194		528,057
Fuel and natural gas in storage	48,982		95,350
Supplies and consumables inventory	178,150		129,571
Regulatory assets (note 7)	142,970		190,393
Prepaid expenses	81,926		58,653
Derivative instruments (note 24)	10,920		12,270
Other assets (note 11)	23,061		22,564
	1,066,345		1,094,481
Property, plant and equipment, net (note 5)	12,517,450		11,944,885
Intangible assets, net (note 6)	93,938		96,683
Goodwill (note 6)	1,324,062		1,320,579
Regulatory assets (note 7)	1,184,713		1,081,108
Long-term investments (note 8)
Investments carried at fair value	1,115,729		1,344,207
Other long-term investments	641,920		462,325
Derivative instruments (note 24)	72,328		71,630
Deferred income taxes (note 18)	158,483		84,416
Other assets (note 11)	198,993		127,299
	$	18,373,961	$	17,627,613

See accompanying notes to consolidated financial statements

Consolidated Financial Statements 76

Algonquin Power & Utilities Corp.

Consolidated Balance Sheets (continued)

(thousands of U.S. dollars)
	December 31,		December 31,
	2023		2022
LIABILITIES AND EQUITY
Current liabilities:
Accounts payable	$	210,412	$	186,080
Accrued liabilities	554,875		555,792
Dividends payable (note 15)	74,916		125,655
Regulatory liabilities (note 7)	99,850		69,865
Long-term debt (note 9)	621,856		423,274
Other long-term liabilities (note 12)	80,458		134,212
Derivative instruments (note 24)	34,915		32,491
Other liabilities	7,898		7,091
	1,685,180		1,534,460
Long-term debt (note 9)	7,894,174		7,088,743
Regulatory liabilities (note 7)	634,446		558,317
Deferred income taxes (note 18)	578,902		565,639
Derivative instruments (note 24)	75,961		137,830
Pension and other post-employment benefits obligation (note 10)	96,653		125,579
Other long-term liabilities (note 12)	465,874		461,230
	9,746,010		8,937,338
Redeemable non-controlling interests (note 17)
Redeemable non-controlling interest, held by related party	308,350		307,856
Redeemable non-controlling interests	10,013		11,520
	318,363		319,376
Equity:
Preferred shares	184,299		184,299
Common shares (note 13(a))	6,229,994		6,183,943
Additional paid-in capital	7,254		9,413
Deficit	(1,279,696)		(997,945)
Accumulated other comprehensive loss (“AOCI”) (note 14)	(102,286)		(160,063)
Total equity attributable to shareholders of Algonquin Power & Utilities Corp.	5,039,565		5,219,647
Non-controlling interests (note 17)
Non-controlling interests - tax equity partnership units	1,196,720		1,225,608
Other non-controlling interests	347,338		333,362
Non-controlling interest, held by related party	40,785		57,822
	1,584,843		1,616,792
Total equity	6,624,408		6,836,439
Commitments and contingencies (note 22)
Subsequent events (notes 3(c), 7(a), 8(c), 9(c), 9(d), 16(a), 17(c))
	$	18,373,961	$	17,627,613

See accompanying notes to consolidated financial statements

Consolidated Financial Statements 77

Algonquin Power & Utilities Corp.

Consolidated Statements of Equity

(thousands of U.S. dollars) For the year ended December 31, 2023
	Algonquin Power & Utilities Corp. Shareholders
	Common shares		Preferred shares		Additional paid-in capital		Retained earnings (deficit)		AOCI		Non- controlling interests		Total
Balance, December 31, 2022	$	6,183,943	$	184,299	$	9,413	$	(997,945)	$	(160,063)	$	1,616,792	$	6,836,439
Net earnings (loss)	—		—		—		28,674		—		(61,979)		(33,305)
Effect of redeemable non-controlling interests not included in equity (note 17)	—		—		—		—		—		(24,598)		(24,598)
OCI	—		—		—		—		57,777		1,017		58,794
Dividends declared and distributions to non-controlling interests	—		—		—		(279,634)		—		(54,322)		(333,956)
Dividends and issuance of shares under dividend reinvestment plan	30,482		—		—		(30,482)		—		—		—
Contributions received from non-controlling interests, net of cost	—		—		—		—		—		107,933		107,933
Common shares issued upon conversion of convertible debentures	11		—		—		—		—		—		11
Common shares issued under employee share purchase plan	5,229		—		—		—		—		—		5,229
Share-based compensation	—		—		13,162		—		—		—		13,162
Common shares issued pursuant to share-based awards	10,329		—		(15,321)		(309)		—		—		(5,301)
Balance, December 31, 2023	$	6,229,994	$	184,299	$	7,254	$	(1,279,696)	$	(102,286)	$	1,584,843	$	6,624,408

See accompanying notes to consolidated financial statements

Consolidated Financial Statements 78

Algonquin Power & Utilities Corp.

Consolidated Statements of Equity (continued)

(thousands of U.S. dollars) For the year ended December 31, 2022
	Algonquin Power & Utilities Corp. Shareholders
	Common shares		Preferred shares		Additional paid-in capital		Deficit		AOCI		Non- controlling interests		Total
Balance, December 31, 2021	$	6,032,792	$	184,299	$	2,007	$	(288,424)	$	(71,677)	$	1,523,082	$	7,382,079
Net loss	—		—		—		(211,989)		—		(96,166)		(308,155)
Effect of redeemable non-controlling interests not included in equity (note 17)	—		—		—		—		—		(8,859)		(8,859)
OCI	—		—		—		—		(88,386)		(1,650)		(90,036)
Dividends declared and distributions to non-controlling interests	—		—		—		(396,965)		—		(61,063)		(458,028)
Dividends and issuance of shares under dividend reinvestment plan	97,801		—		—		(97,801)		—		—		—
Contributions received from non-controlling interests, net of cost	—		—		—		—		—		273,697		273,697
Common shares issued upon conversion of convertible debentures	6		—		—		—		—		—		6
Common shares issued upon public offering, net of tax effected cost	38,227		—		—		—		—		—		38,227
Common shares issued under employee share purchase plan	5,319		—		—		—		—		—		5,319
Share-based compensation	—		—		14,849		—		—		—		14,849
Common shares issued pursuant to share-based awards	9,798		—		(14,743)		(2,766)		—		—		(7,711)
Non-controlling interest assumed on asset acquisition	—		—		7,300		—		—		(12,249)		(4,949)
Balance, December 31, 2022	$	6,183,943	$	184,299	$	9,413	$	(997,945)	$	(160,063)	$	1,616,792	$	6,836,439

See accompanying notes to consolidated financial statements

Consolidated Financial Statements 79

Algonquin Power & Utilities Corp.

Consolidated Statements of Cash Flows

(thousands of U.S. dollars)	Years ended December 31
	2023		2022
Cash provided by (used in):
Operating activities
Net loss	$	(33,305)	$	(308,155)
Adjustments and items not affecting cash:
Depreciation and amortization	466,996		455,520
Deferred taxes	(76,560)		(69,356)
Initial value and changes in derivative financial instruments net of amortization	(15,502)		2,462
Share-based compensation	10,397		10,920
Cost of equity funds used for construction purposes	(3,366)		(1,896)
Change in value of investments carried at fair value	229,988		499,125
Pension and post-employment expense lower than contributions	(7,838)		(15,329)
Distributions received from equity investments, net of income	11,730		23,829
Impairment of assets (notes 5 and 8(c))	23,492		235,478
Other (notes 19(c), 19(e) and 19(f))	108,338		8,116
Net change in non-cash operating items (note 23)	(86,336)		(221,618)
	628,034		619,096
Financing activities
Increase in long-term debt	3,033,503		4,622,937
Repayments of long-term debt	(2,297,346)		(3,326,519)
Net change in commercial paper	74,720		68,300
Issuance of common shares, net of costs	5,229		43,546
Cash dividends on common shares	(322,468)		(378,597)
Dividends on preferred shares	(8,356)		(8,720)
Contributions from non-controlling interests and redeemable non-controlling interests (note 3)	98,955		272,515
Production-based cash contributions from non-controlling interest	9,084		6,182
Distributions to non-controlling interests, related party (note 17)	(25,428)		(34,816)
Distributions to non-controlling interests	(51,164)		(43,919)
Payments upon settlement of derivatives	—		(28,913)
Shares surrendered to fund withholding taxes on exercised share options	(2,434)		(4,667)
Redemption of Series C preferred shares (note 12(h))	(14,515)		—
Acquisition of non-controlling interest	—		(1,580)
Increase in other long-term liabilities	22,666		19,324
Decrease in other long-term liabilities	(79,638)		(94,837)
	442,808		1,110,236
Investing activities
Additions to property, plant and equipment and intangible assets	(1,026,171)		(1,089,024)
Increase in long-term investments	(243,742)		(221,281)
Acquisitions of operating entities	—		(632,797)
Increase in other assets	(12,220)		(26,527)
Receipt of principal on development loans receivable	174,763		178,300
Decrease in long-term investments	11,749		2,920
	(1,095,621)		(1,788,409)
Effect of exchange rate differences on cash and restricted cash	(267)		(1,127)
Decrease in cash, cash equivalents and restricted cash	(25,046)		(60,204)
Cash, cash equivalents and restricted cash, beginning of year	101,185		161,389
Cash, cash equivalents and restricted cash, end of year	$	76,139	$	101,185

See accompanying notes to consolidated financial statements

Consolidated Financial Statements 80

Algonquin Power & Utilities Corp. Consolidated Statements of Cash Flows (continued)
(thousands of U.S. dollars)	Years ended December 31
	2023		2022
Supplemental disclosure of cash flow information:
Cash paid during the year for interest expense	$	368,511	$	272,734
Cash paid during the year for income taxes	$	7,171	$	10,962
Cash received during the year for distributions from equity investments	$	112,716	$	112,951
Non-cash financing and investing activities:
Property, plant and equipment acquisitions in accruals	$	172,165	$	120,819
Issuance of common shares under dividend reinvestment plan and share-based compensation plans	$	46,040	$	112,918
Property, plant and equipment, intangible assets and accrued liabilities in exchange of note receivable	$	23,938	$	90,700

See accompanying notes to consolidated financial statements

Consolidated Financial Statements 81

Algonquin Power & Utilities Corp.

Notes to the Consolidated Financial Statements

December 31, 2023 and 2022

(in thousands of U.S. dollars, except as noted and per share amounts)

Algonquin Power & Utilities Corp. (“AQN” or the “Company”) is an incorporated entity under the Canada Business CorporationsAct. AQN’s operations are organized across two primary business units consisting of the Regulated Services Group and the Renewable Energy Group. The Regulated Services Group primarily owns and operates a portfolio of regulated electric, water distribution and wastewater collection, and natural gas utility systems and transmission operations in the United States, Canada, Bermuda and Chile; the Renewable Energy Group primarily owns and operates, or has investments in, a diversified portfolio of non-regulated renewable and thermal energy generation assets.

1.Significant accounting policies

(a)Basis of preparation

The accompanying consolidated financial statements and notes have been prepared in accordance with generally accepted accounting principles in the United States (“U.S. GAAP”) and follow disclosure required under Regulation S-X provided by the U.S. Securities and Exchange Commission.

(b)Basis of consolidation

The accompanying consolidated financial statements of AQN include the accounts of AQN and variable interest entities (“VIEs”) where the Company is the primary beneficiary (note 1(m)). Intercompany transactions and balances have been eliminated. Interests in subsidiaries owned by third parties are included in non-controlling interests (note 1(s)).

(c)Business combinations, intangible assets and goodwill

The Company accounts for acquisitions of entities or assets that meet the definition of a business as business combinations. Business combinations are accounted for using the acquisition method. Assets acquired and liabilities assumed are measured at their fair value at the acquisition date, except for deferred income taxes, which are accounted for as described in note 1(v). Acquisition costs are expensed in the period incurred. When the set of activities does not represent a business, the transaction is accounted for as an asset acquisition and includes acquisition costs.

Intangible assets acquired are recognized separately at fair value if they arise from contractual or other legal rights or are separable. Power sales contracts are amortized on a straight-line basis over the remaining term of the contract ranging from 6 to 25 years from the date of acquisition. Interconnection agreements are amortized on a straight-line basis over their estimated life of 40 years. The majority of the Company’s customer relationships are amortized on a straight-line basis over their estimated lives of 25 to 40 years. Certain customer relationships and water rights in Chile as well as brand names are considered indefinite-lived intangibles and are not amortized, but assessed annually for indicators of impairment. Miscellaneous intangibles include renewable energy credits that are purchased by the Company’s electric utilities to satisfy renewable portfolio standard obligations. These intangibles are not amortized but are derecognized when remitted to the respective state authority to satisfy the compliance obligation.

Goodwill represents the excess of the purchase price of an acquired business over the fair value of the net assets acquired. Goodwill is generally not included in the rate base on which regulated utilities are allowed to earn a return and is not amortized.

As at September 30 of each year, the Company assesses qualitative and quantitative factors to determine whether it is more likely than not that the fair value of a reporting unit to which goodwill is attributed is less than its carrying amount. If it is more likely than not that a reporting unit’s fair value is less than its carrying amount or if a quantitative assessment is elected, the Company calculates the fair value of the reporting unit. If the carrying amount of the reporting unit as a whole exceeds the reporting unit’s fair value, an impairment charge is recorded in an amount of that excess, limited to the total amount of goodwill allocated to that reporting unit. Goodwill is tested for impairment between annual tests if an event occurs or circumstances change that would more likely than not reduce the fair value of a reporting unit below its carrying amount.

Notes to the Consolidated Financial Statements 82

Algonquin Power & Utilities Corp.

Notes to the Consolidated Financial Statements

December 31, 2023 and 2022

(in thousands of U.S. dollars, except as noted and per share amounts)

1.Significant accounting policies (continued)

(d)Accounting for rate-regulated operations

The operating companies within the Regulated Services Group are subject to rate regulation generally overseen by the regulatory authorities of the jurisdictions in which they operate (the “Regulator”). The Regulator provides the final determination of the rates charged to customers. AQN’s regulated operating companies are accounted for under the principles of U.S. Financial Accounting Standards Board (“FASB”) ASC Topic 980, Regulated Operations (“ASC 980”) except for AQN’s Chilean operating company, Suralis (Chile) Water System (“Suralis”) (formerly known as Empresa de Servicios Sanitarios de Los Lagos (ESSAL). The rates that are approved under the Chilean regulatory framework are designed to recover the costs of service of a model water utility. Because the rates are not designed to recover Suralis’s specific costs of service, the utility does not meet the criteria to follow the accounting guidance under ASC 980.

Under ASC 980, regulatory assets and liabilities are recorded to the extent that they represent probable future revenue or expenses associated with certain charges or credits that will be recovered from or refunded to customers through the rate-making process. Included in note 7, “Regulatory matters”, are details of regulatory assets and liabilities, and their current regulatory treatment.

In the event the Company determines that its net regulatory assets are not probable of recovery, it would no longer apply the principles of the current accounting guidance for rate-regulated enterprises and would be required to record an after-tax, non-cash charge or credit against earnings for any remaining regulatory assets or liabilities. The impact could be material to the Company’s reported consolidated financial condition and consolidated results of operations.

The U.S. electric, gas and water utilities’ accounts are maintained in accordance with the Uniform System of Accounts prescribed by the Federal Energy Regulatory Commission (“FERC”), the applicable Regulator(s) and National Association of Regulatory Utility Commissioners in the United States. The New Brunswick Gas accounts are maintained in accordance with the Gas Distribution Uniform Accounting Regulation - Gas Distribution Act, 1999 (New Brunswick).

(e)Cash and cash equivalents

Cash and cash equivalents include all highly liquid instruments with an original maturity of three months or less.

(f)Restricted cash

Restricted cash represents reserves and amounts set aside pursuant to requirements of various debt agreements, deposits to be returned back to customers, and certain requirements related to generation and transmission operations. Cash reserves segregated from AQN’s cash balances are maintained in accounts administered by a separate agent and disclosed separately as restricted cash in these consolidated financial statements. AQN cannot access restricted cash without the prior authorization of parties not related to AQN.

(g)Accounts receivable

Trade accounts receivable are recorded at the invoiced amount and do not bear interest. The Company maintains an allowance for doubtful accounts for estimated losses inherent in its accounts receivable portfolio. In establishing the required allowance, management considers historical losses adjusted to take into account current market conditions and customers’ financial condition, the amount of receivables in dispute, future economic conditions and outlook, and the receivables aging and current payment patterns. Account balances are charged against the allowance after all means of collection have been exhausted and the potential for recovery is considered remote. The Company does not have any off-balance sheet credit exposure related to its customers.

Notes to the Consolidated Financial Statements 83

Algonquin Power & Utilities Corp.

Notes to the Consolidated Financial Statements

December 31, 2023 and 2022

(in thousands of U.S. dollars, except as noted and per share amounts)

1.Significant accounting policies (continued)

(h)Fuel and natural gas in storage

Fuel and natural gas in storage is reflected at weighted average cost or first-in-first-out as required by regulators and represents fuel, natural gas and liquefied natural gas that will be utilized in the ordinary course of business of the gas utilities and some generating facilities. Existing rate orders and other contracts allow the Company to pass through the cost of gas purchased directly to the customers along with any applicable authorized delivery surcharge adjustments (note 7(a)). Accordingly, the net realizable value of fuel and gas in storage does not fall below the cost to the Company.

(i)Supplies and consumables inventory

Supplies and consumables inventory (other than capital spares and rotatable spares, which are included in property, plant and equipment) are charged to inventory when purchased and then capitalized to plant or expensed, as appropriate, when installed, used or upon becoming obsolete. These items are stated at the lower of cost and net realizable value. Through rate orders and the regulatory environment, capitalized construction jobs are recovered through rate base, and repair and maintenance expenses are recovered through a cost of service calculation. Accordingly, the cost usually reflects the net realizable value.

(j)Property, plant and equipment

Property, plant and equipment are recorded at cost. Capitalization of development projects begins when it is probable that costs will be realized through the use of the asset or ultimate construction and operation of a facility. Project development costs for rate-regulated entities, including expenditures for preliminary surveys, plans, investigations, environmental studies, regulatory applications and other costs incurred for the purpose of determining the feasibility of capital expansion projects, are capitalized either as regulatory assets or property, plant and equipment when it is determined that recovery of such costs through regulated revenue of the completed project is probable.

The costs of acquiring or constructing property, plant and equipment include the following: materials, labour, contractor and professional services, construction overhead directly attributable to the capital project (where applicable), interest for non-regulated property and allowance for funds used during construction (“AFUDC”) for regulated property. Where possible, individual components are recorded and depreciated separately in the books and records of the Company. Plant and equipment under finance leases are initially recorded at cost determined as the present value of lease payments to be made over the lease term.

AFUDC represents the cost of borrowed funds and a return on other funds. Under ASC 980, an allowance for funds used during construction projects that are included in rate base is capitalized. This allowance is designed to enable a utility to capitalize financing costs during periods of construction of property subject to rate regulation. For operations that do not apply regulatory accounting, interest related only to debt is capitalized as a cost of construction in accordance with ASC 835, Interest. The interest capitalized that relates to debt reduces interest expense on the consolidated statements of operations. The AFUDC capitalized that relates to equity funds is recorded as interest and other income under income from long-term investments on the consolidated statements of operations.

Improvements that increase or prolong the service life or capacity of an asset are capitalized. Costs incurred for major expenditures or overhauls that occur at regular intervals over the life of an asset are capitalized and depreciated over the related interval. Maintenance and repair costs are expensed as incurred. Grants related to capital expenditures are recorded as a reduction to the cost of assets and are amortized at the rate of the related asset as a reduction to depreciation expense. Grants related to operating expenses such as maintenance and repairs costs are recorded as a reduction of the related expense. Contributions in aid of construction represent amounts contributed by customers, governments and developers to assist with the funding of some or all of the cost of utility capital assets. They also include amounts initially recorded as advances in aid of construction (note 12(c)) once the advance repayment period has expired. These contributions are recorded as a reduction in the cost of utility assets and are amortized at the rate of the related asset as a reduction to depreciation expense.

Notes to the Consolidated Financial Statements 84

Algonquin Power & Utilities Corp.

Notes to the Consolidated Financial Statements

December 31, 2023 and 2022

(in thousands of U.S. dollars, except as noted and per share amounts)

1.Significant accounting policies (continued)

(j)Property, plant and equipment (continued)

The Company’s depreciation is based on the estimated useful lives of the depreciable assets in each category and is determined using the straight-line method with the exception of certain wind assets, as described below. The ranges of estimated useful lives and the weighted average useful lives are summarized below:

	Range of useful lives		Weighted average useful lives
	2023	2022	2023	2022
Generation	3-60	3-60	33	33
Distribution	1-100	1-100	40	39
Equipment	5-54	5-54	15	11

The Company uses the unit-of-production method for certain components of its wind-generating facilities where the useful life of the component is directly related to the amount of production. The benefits of components subject to wear and tear from the power generation process are best reflected through the unit-of-production method. The Company generally uses wind studies prepared by third parties to estimate the total expected production of each component.

In accordance with regulator-approved accounting policies, when depreciable property, plant and equipment of the Regulated Services Group are replaced or retired, the original cost plus any removal costs incurred (net of salvage) are charged to accumulated depreciation with no gain or loss reflected in results of operations. Gains and losses will be charged to results of operations in the future through adjustments to depreciation expense. In the absence of regulator-approved accounting policies, gains and losses on the disposition of property, plant and equipment are charged to earnings as incurred.

(k)Commonly owned facilities

The Regulated Services Group owns undivided interests in three electric-generating facilities with ownership interest ranging from 7.52% to 60%, with a corresponding share of capacity and generation from the facility used to serve certain of its utility customers. The Company’s investment in the undivided interest is recorded as plant in service and recovered through rate base. Commonly owned facilities represent cost of $552,701 (2022 - $559,630) and accumulated depreciation of $83,283 (2022 - $75,820). The Company’s share of operating costs are recognized in operating expenses. Total expenditures incurred on these facilities for the year ended December 31, 2023 were $72,584 (2022 - $110,268).

(l)Impairment of long-lived assets

AQN reviews property, plant and equipment and finite-life intangible assets for impairment whenever events or changes in circumstances indicate the carrying amount may not be recoverable.

As at September 30 of each year, the Company assesses qualitative factors to determine whether it is more likely than not that the indefinite-lived intangible is impaired. If it is more likely than not that the indefinite-lived intangible asset is impaired, the Company calculates the fair value of the intangible asset. If the carrying value of the intangible asset exceeds its fair value, the Company recognizes an impairment loss in an amount equal to that excess. Indefinite-life intangibles are tested for impairment between annual tests if an event occurs or circumstances change that would more likely than not reduces the fair value below its carrying amount.

Recoverability of assets expected to be held and used is measured by comparing the carrying amount of an asset to undiscounted expected future cash flows. If the carrying amount exceeds the recoverable amount, the asset is written down to its fair value.

Notes to the Consolidated Financial Statements 85

Algonquin Power & Utilities Corp.

Notes to the Consolidated Financial Statements

December 31, 2023 and 2022

(in thousands of U.S. dollars, except as noted and per share amounts)

1.Significant accounting policies (continued)

(m)Variable interest entities

The Company performs analyses to assess whether its operations and investments represent VIEs. To identify potential VIEs, management reviews contracts under leases, long-term purchase power agreements and jointly owned facilities. VIEs for which the Company is deemed the primary beneficiary are consolidated. In circumstances where AQN is not deemed the primary beneficiary, the VIE is not consolidated (note 8).

The Company has equity and notes receivable interests in two power-generating facilities. AQN has determined that these entities are considered VIEs mainly based on total equity at risk not being sufficient to permit the legal entity to finance its activities without additional subordinated financial support. The key decisions that affect the generating facilities’ economic performance relate to siting, permitting, technology, construction, operations and maintenance and financing. As AQN has both the power to direct the activities of the entities that most significantly impact its economic performance and the right to receive benefits or the obligation to absorb losses of the entities that could potentially be significant to the entities, the Company is considered the primary beneficiary.

Total net book values of assets and long-term debt of these facilities amount to $57,740 (2022 - $57,241) and $12,738 (2022 - $15,024), respectively. The financial performance of these entities reflected on the consolidated statements of operations includes non-regulated energy sales of $17,317 (2022 - $19,752), operating expenses and amortization of $5,986 (2022 - $5,834) and interest expense of $1,384 (2022 - $1,723).

(n)Long-term investments and development loans

Investments in which AQN has significant influence but not control are either accounted for using the equity method or at fair value. Equity-method investments are initially measured at cost including transaction costs and interest when applicable. AQN records its share in the income or loss of its equity-method investees in income from long-term investments in the consolidated statements of operations. AQN records in the consolidated statements of operations the fluctuations in the fair value of its investees held at fair value and dividend income when it is declared by the investee.

Notes receivable are financial assets with fixed or determined payments that are not quoted in an active market. Notes receivable are initially recorded at cost, which is generally face value. Subsequent to acquisition, the notes receivable are recorded at amortized cost using the effective interest method. The Company holds these notes receivable as long-term investments and does not intend to sell these instruments prior to maturity. Interest from long-term investments is recorded as earned and when collectability of both the interest and principal are reasonably assured.

If a loss in value of a long-term investment is considered other than temporary, an allowance for impairment on the investment is recorded for the amount of that loss. An allowance on notes receivable is recorded in order to present the net amount expected to be collected on the receivable. This allowance reflects the risk of loss over the remaining contractual life of the asset, taking into consideration historical experience, current conditions, and reasonable and supportable forecasts of future economic conditions. The impairment is measured based on the present value of expected future cash flows discounted at the note’s effective interest rate.

Notes to the Consolidated Financial Statements 86

Algonquin Power & Utilities Corp.

Notes to the Consolidated Financial Statements

December 31, 2023 and 2022

(in thousands of U.S. dollars, except as noted and per share amounts)

1.Significant accounting policies (continued)

(o)Pension and other post-employment plans

The Company has established defined contribution pension plans, defined benefit pension plans, other post-employment benefit (“OPEB”) plans and supplemental retirement program (“SERP”) plans for its various employee groups. Employer contributions to the defined contribution pension plans are expensed as employees render service. The Company recognizes the funded status of its defined benefit pension plans, OPEB and SERP plans on the consolidated balance sheets. The Company’s expense and liabilities are determined by actuarial valuations, using assumptions that are evaluated annually as of December 31, including discount rates, mortality, assumed rates of return, compensation increases, turnover rates and healthcare cost trend rates. The impact of modifications to those assumptions and modifications to prior services are recorded as actuarial gains and losses in accumulated other comprehensive income (loss) (“AOCI”) and amortized to net periodic cost over future periods using the corridor method. When settlements of the Company's pension plans occur, the Company recognizes associated gains or losses immediately in earnings if the cost of all settlements during the year is greater than the sum of the service cost and interest cost components of the pension plan for the year. The amount recognized is a pro rata portion of the gains and losses in AOCI equal to the percentage reduction in the projected benefit obligation as a result of the settlement.

The costs of the Company’s pension for employees are expensed over the periods during which employees render service and the service costs are recognized as part of administrative expenses in the consolidated statements of operations. The components of net periodic benefit cost other than the service cost component are included in Pension and other post-employment non-service costs in the consolidated statements of operations.

(p)Asset retirement obligations

The Company recognizes a liability for asset retirement obligations based on the fair value of the liability when incurred, which is generally upon acquisition, during construction or through the normal operation of the asset. Concurrently, the Company also capitalizes an asset retirement cost, equal to the estimated fair value of the asset retirement obligation, by increasing the carrying value of the related long-lived asset. The asset retirement costs are depreciated over the asset’s estimated useful life and are included in depreciation and amortization expense on the consolidated statements of operations. Increases in the asset retirement obligation resulting from the passage of time are recorded as accretion of asset retirement obligation in the consolidated statements of operations. Actual expenditures incurred are charged against the obligation.

(q)Leases

The Company accounts for leases in accordance with ASC Topic 842, Leases. The Company leases land, buildings, vehicles, rail cars and office equipment for use in its day-to-day operations. The Company has options to extend the lease term of many of its lease agreements, with renewal periods ranging from one to five years.

The Renewable Energy Group enters into land easement agreements for the operation of its generation facilities. In assessing whether these contracts contain leases, the Company considers whether it has exclusive use of the land. In the majority of situations, the landowner or grantor of the easement still has full access to the land and can use the land in any capacity, as long as it does not interfere with the Company’s operations. Therefore, these land easement agreements do not contain leases. For land easement agreements that provide exclusive access to and use of the land, these agreements meet the definition of a lease and are within the scope of ASC 842.

The right-of-use assets are included in property, plant and equipment while lease liabilities are included in other liabilities on the consolidated balance sheets. The discount rates used in the measurement of the Company’s right-of-use assets and liabilities are the discount rates at the date of lease inception. The Company’s lease balances as of December 31, 2023 and its expected lease payments for the next five years and thereafter are not significant.

Notes to the Consolidated Financial Statements 87

Algonquin Power & Utilities Corp.

Notes to the Consolidated Financial Statements

December 31, 2023 and 2022

(in thousands of U.S. dollars, except as noted and per share amounts)

1.Significant accounting policies (continued)

(r)Share-based compensation

The Company has several share-based compensation plans: a share option plan; an employee share purchase plan (“ESPP”); a deferred share unit (“DSU”) plan; and a restricted share unit (“RSU”) and performance share unit (“PSU”) plan. Equity-classified awards are measured at the grant date fair value of the award. The Company estimates grant date fair value of options using the Black-Scholes option pricing model. The fair value is recognized over the vesting period of the award granted, adjusted for estimated forfeitures. The compensation cost is recorded as administrative expenses in the consolidated statements of operations and additional paid-in capital in equity. Additional paid-in capital is reduced as the awards are exercised, and the amount initially recorded in additional paid-in capital is credited to common shares.

(s)Non-controlling interests

Non-controlling interests represent the portion of equity ownership in subsidiaries that is not attributable to the equity holders of AQN. Non-controlling interests are initially recorded at fair value and subsequently adjusted for the proportionate share of earnings (loss) and other comprehensive income (loss) (“OCI”) attributable to the non-controlling interests and any dividends or distributions paid to the non-controlling interests.

If a transaction results in the acquisition of all, or part, of a non-controlling interest in a consolidated subsidiary, the acquisition of the non-controlling interest is accounted for as an equity transaction. No gain or loss is recognized in net earnings (loss) or comprehensive income (loss) as a result of changes in the non-controlling interest, unless a change results in the loss of control by the Company.

Certain of the Company’s U.S.-based wind and solar businesses are organized as limited liability corporations (“LLCs”) and partnerships, and have non-controlling membership equity investors (“tax equity partnership units”, or “Tax Equity Investors”), which are entitled to allocations of earnings, tax attributes and cash flows in accordance with contractual agreements. These LLCs and partnership agreements have liquidation rights and priorities that are different from the underlying percentage ownership interests. In those situations, simply applying the percentage ownership interest to U.S. GAAP net income in order to determine earnings or losses would not accurately represent the income allocation and cash flow distributions that will ultimately be received by the investors. As such, the share of earnings attributable to the non-controlling interest holders in these entities is calculated using the Hypothetical Liquidation at Book Value (“HLBV”) method of accounting (note 17).

The HLBV method uses a balance sheet approach. A calculation is prepared as at each balance sheet date to

determine the amount that Tax Equity Investors would receive if an equity investment entity were to liquidate all of its assets and distribute that cash to the investors based on the contractually defined liquidation priorities. The difference between the calculated liquidation distribution amounts at the beginning and the end of the reporting period is the Tax Equity Investors’ share of the earnings or losses from the investment for that period.

Equity instruments subject to redemption upon the occurrence of uncertain events not solely within AQN’s control are classified as temporary equity and presented as redeemable non-controlling interests on the consolidated balance sheets. The Company records temporary equity at issuance based on cash received less any transaction costs. As needed, the Company reevaluates the classification of its redeemable instruments, as well as the probability of redemption. If the redemption amount is probable or currently redeemable, the Company records the instruments at their redemption value. Increases or decreases in the carrying amount of a redeemable instrument are recorded within deficit. When the redemption feature lapses or other events cause the classification of an equity instrument as temporary equity to be no longer required, the existing carrying amount of the equity instrument is reclassified to permanent equity at the date of the event that caused the reclassification.

(t)Recognition of revenue

Revenue is recognized when control of the promised goods or services is transferred to the Company’s customers in an amount that reflects the consideration the Company expects to be entitled to in exchange for those goods or services. Refer to note 21, “Segmented information” for details of revenue disaggregation by business units.

Notes to the Consolidated Financial Statements 88

Algonquin Power & Utilities Corp.

Notes to the Consolidated Financial Statements

December 31, 2023 and 2022

(in thousands of U.S. dollars, except as noted and per share amounts)

1.Significant accounting policies (continued)

(t)Recognition of revenue (continued)

Regulated Services Group revenue

Regulated Services Group revenue derives primarily from the distribution and generation of electricity, water distribution, wastewater collection and distribution of natural gas.

Revenue related to utility electricity and natural gas sales and distribution is recognized over time as the energy is delivered. At the end of each month, the electricity and natural gas delivered to the customers from the date of their last meter read to the end of the month is estimated and the corresponding unbilled revenue is recorded. These estimates of unbilled revenue and sales are based on the ratio of billable days versus unbilled days, amount of electricity or natural gas procured during that month, historical customer class usage patterns, weather, line loss, unaccounted-for natural gas and current tariffs. Unbilled receivables are typically billed within the next month. Some customers elect to pay their bill on an equal monthly plan.

As a result, in some months cash is received in advance of the delivery of electricity. Deferred revenue is recorded for that amount. The amount of revenue recognized in the period from the balance of deferred revenue is not significant.

Water reclamation and distribution revenue is recognized over time when water is processed or delivered to customers. At the end of each month, the water delivered and wastewater collected from the customers from the date of their last meter read to the end of the month are estimated and the corresponding unbilled revenue is recorded. These estimates of unbilled revenue are based on the ratio of billable days versus unbilled days, amount of water procured and collected during that month, historical customer class usage patterns and current tariffs. Unbilled receivables are typically billed within the next month.

On occasion, a utility is permitted to implement new rates that have not been formally approved by the regulatory commission, which are subject to refund. The Company recognizes revenue based on the interim rate and, if needed, establishes a reserve for amounts that could be refunded based on experience for the jurisdiction in which the rates were implemented.

Revenue for certain of the Company’s regulated utilities is subject to alternative revenue programs approved by their respective regulators. Under these programs, the Company charges approved annual delivery revenue on a systematic basis over the fiscal year. As a result, the difference between delivery revenue calculated based on metered consumption and approved delivery revenue is disclosed as alternative revenue in note 21, “Segmented information” and is recorded as a regulatory asset or liability to reflect future recovery or refund, respectively, from customers (note 7). The amount subsequently billed to customers is recorded as a recovery of the regulatory asset.

Renewable Energy Group revenue

Renewable Energy Group’s revenue derives primarily from the sale of electricity, capacity and renewable energy credits.

Revenue related to the sale of electricity is recognized over time as the electricity is delivered. The electricity represents a single performance obligation that represents a promise to transfer to the customer a series of distinct goods that are substantially the same and that have the same pattern of transfer to the customer.

Revenue related to the sale of capacity is recognized over time as the capacity is provided. The nature of the promise to provide capacity is that of a stand-ready obligation. The capacity is generally expressed in monthly volumes and prices. The capacity represents a single performance obligation that represents a promise to transfer to the customer a series of distinct services that are substantially the same and that have the same pattern of transfer to the customer.

Notes to the Consolidated Financial Statements 89

Algonquin Power & Utilities Corp.

Notes to the Consolidated Financial Statements

December 31, 2023 and 2022

(in thousands of U.S. dollars, except as noted and per share amounts)

1.Significant accounting policies (continued)

(t)Recognition of revenue (continued)

Renewable Energy Group revenue (continued)

Qualifying renewable energy projects receive renewable energy credits (“RECs”) and solar renewable energy credits (“SRECs”) for the generation and delivery of renewable energy to the power grid. The energy credit certificates represent proof that 1 MW of electricity was generated from an eligible energy source. The RECs and SRECs can be traded and the owner of the RECs or SRECs can claim to have purchased renewable energy. RECs and SRECs are primarily sold under fixed contracts, and revenue for these contracts is recognized at a point in time, upon generation of the associated electricity. Any RECs or SRECs generated above contracted amounts are held in inventory, with the offset recorded as a decrease in operating expenses.

The Company applies the invoicing expedient to the electricity and capacity in the Renewable Energy Group contracts. As such, revenue is recognized at the amount to which the Company has the right to invoice for services performed. Revenue is recorded net of sales taxes.

(u)Foreign currency translation

AQN’s reporting currency is the U.S. dollar. Within these consolidated financial statements, the Company denotes any amounts denominated in Canadian dollars with “C$”, in Chilean pesos with “CLP” and in Chilean Unidad de Fomento with “CLF” immediately prior to the stated amounts.

The Company’s Canadian operations have the Canadian dollar as their functional currency since the preponderance of operating, financing and investing transactions are denominated in Canadian dollars. Similarly, the Company’s Chilean and Bermudian operations’ functional currency is the Chilean peso and the Bermudian dollar, respectively. The financial statements of these operations are translated into U.S. dollars using the current rate method, whereby assets and liabilities are translated at the rate prevailing as at the balance sheet date, and revenue and expenses are translated using average rates for the period. Unrealized gains or losses arising as a result of the translation of the financial statements of these entities are reported as a component of OCI and are accumulated in a component of equity on the consolidated balance sheets, and are not recorded in income unless there is a complete or substantially complete sale or liquidation of the investment.

(v)Income taxes

Income taxes are accounted for using the asset and liability method. Deferred tax assets and liabilities are recognized for the future tax consequences attributable to differences between the consolidated financial statement carrying amounts of assets and liabilities and their respective tax bases. Deferred tax assets and liabilities are measured using enacted tax rates expected to apply to taxable income in the years in which those temporary differences are expected to be recovered or settled. A valuation allowance is recorded against deferred tax assets to the extent that it is considered more likely than not that the deferred tax asset will not be realized. The effect on deferred tax assets and liabilities of a change in tax rates is recognized in earnings in the period that includes the date of enactment. Investment tax credits for the rate-regulated operations are deferred and amortized as a reduction to income tax expense over the estimated useful lives of the properties. Investment tax credits along with other income tax credits in the non-regulated operations are treated as a reduction to income tax expense in the year the credit arises.

The organizational structure of AQN and its subsidiaries is complex and the related tax interpretations, regulations and legislation in the tax jurisdictions in which they operate are continually changing. As a result, there can be tax matters that have uncertain tax positions. The Company recognizes the effect of income tax positions only if those positions are more likely than not of being sustained. Recognized income tax positions are measured at the largest amount that is greater than 50% likely of being realized. Changes in recognition or measurement are reflected in the period in which the change in judgment occurs.

Notes to the Consolidated Financial Statements 90

Algonquin Power & Utilities Corp.

Notes to the Consolidated Financial Statements

December 31, 2023 and 2022

(in thousands of U.S. dollars, except as noted and per share amounts)

1.Significant accounting policies (continued)

(w)Financial instruments and derivatives

Accounts receivable and notes receivable are measured at amortized cost. Long-term debt and preferred shares, Series C (redeemed during the year) are measured at amortized cost using the effective interest method, adjusted for the amortization or accretion of premiums or discounts.

Transaction costs that are directly attributable to the acquisition of financial assets are accounted for as part of the asset’s carrying value at inception. Transaction costs related to a recognized debt liability are presented in the consolidated balance sheets as a direct deduction from the carrying amount of that debt liability, consistent with debt discounts and premiums. Costs of arranging the Company’s revolving credit facilities, Green equity units (note 11(a)) and intercompany loans are recorded in other assets. Deferred financing costs, premiums and discounts on long-term debt are amortized using the effective interest method while deferred financing costs relating to the revolving credit facilities and intercompany loans are amortized on a straight-line basis over the term of the respective instrument.

The Company uses derivative financial instruments as one method to manage exposures to fluctuations in exchange rates, interest rates and commodity prices. AQN recognizes all derivative instruments as either assets or liabilities on the consolidated balance sheets at their respective fair values. The fair value recognized on derivative instruments executed with the same counterparty under a master netting arrangement are presented on a gross basis on the consolidated balance sheets. The amounts that could net settle are not significant. The Company applies hedge accounting to some of its financial instruments used to manage its foreign currency risk, interest rate risk and price risk exposures associated with sales of generated electricity.

For derivatives designated in a cash flow hedge relationship, the change in fair value is recognized in OCI.

The amount recognized in AOCI is reclassified to earnings (loss) in the same period as the hedged cash flows affect earnings under the same line item in the consolidated statements of operations as the hedged item. If the hedging instrument no longer meets the criteria for hedge accounting, expires or is sold, terminated, exercised, or the designation is revoked, then hedge accounting is discontinued prospectively. The amount remaining in AOCI is transferred to the consolidated statements of operations in the same period that the hedged item affects earnings. If the forecasted transaction is no longer expected to occur, then the balance in AOCI is recognized immediately in earnings (loss).

Foreign currency gain or loss on derivative or financial instruments designated as a hedge of the foreign currency exposure of a net investment in foreign operations that are effective as a hedge is reported in the same manner as the translation adjustment (in OCI) related to the net investment.

The Company’s electric distribution and thermal generation facilities enter into power and natural gas purchase contracts for load serving and generation requirements. These contracts meet the exemption for normal purchase and normal sales and, as such, are not required to be recorded at fair value as derivatives and are accounted for on an accrual basis. Counterparties are evaluated on an ongoing basis for non-performance risk to ensure it does not impact the conclusion with respect to this exemption.

(x)Fair value measurements

The Company utilizes valuation techniques that maximize the use of observable inputs and minimize the use of unobservable inputs to the extent possible. The Company determines fair value based on assumptions that market participants would use in pricing an asset or liability in the principal or most advantageous market. When considering market participant assumptions in fair value measurements, the following fair value hierarchy distinguishes between observable and unobservable inputs, which are categorized in one of the following levels:

•Level 1 Inputs: Unadjusted quoted prices in active markets for identical assets or liabilities accessible to the reporting entity at the measurement date.

•Level 2 Inputs: Other than quoted prices included in Level 1, inputs that are observable for the asset or liability, either directly or indirectly, for substantially the full term of the asset or liability.

•Level 3 Inputs: Unobservable inputs for the asset or liability used to measure fair value to the extent that observable inputs are not available, thereby allowing for situations in which there is little, if any, market activity for the asset or liability at the measurement date.

Notes to the Consolidated Financial Statements 91

Algonquin Power & Utilities Corp.

Notes to the Consolidated Financial Statements

December 31, 2023 and 2022

(in thousands of U.S. dollars, except as noted and per share amounts)

1.Significant accounting policies (continued)

(y)Commitments and contingencies

Liabilities for loss contingencies arising from environmental remediation, claims, assessments, litigation, fines, penalties and other sources are recorded when it is probable that a liability has been incurred and the amount can be reasonably estimated. Legal costs incurred in connection with loss contingencies are expensed as incurred.

(z)Use of estimates

The preparation of financial statements requires management to make estimates and assumptions that affect the reported amounts of assets and liabilities and disclosure of contingent assets and liabilities as at the date of these consolidated financial statements and the reported amounts of revenue and expenses during the year. Actual results could differ from those estimates. During the years presented, management has made a number of estimates and valuation assumptions, including the useful lives and recoverability of property, plant and equipment, intangible assets and goodwill; the recoverability of notes receivable and long-term investments; the recoverability of deferred tax assets; assessments of unbilled revenue; pension and OPEB obligations; timing effect of regulated assets and liabilities; contingencies related to environmental matters; the fair value of assets and liabilities acquired in a business combination; and the fair value of financial instruments. These estimates and valuation assumptions are based on present conditions and management’s planned course of action, as well as assumptions about future business and economic conditions. Should the underlying valuation assumptions and estimates change, the recorded amounts could change by a material amount.

2.     Recently issued accounting pronouncements

(a)Recently adopted accounting pronouncements

The FASB issued Accounting Standards Update (“ASU”) 2022-04, Liabilities — Supplier Finance Programs (Subtopic 405-50): Disclosure of Supplier Finance Program Obligations, which require that a buyer in a supplier finance program disclose sufficient information about the program to allow a user of financial statements to understand the program’s nature, activity during the period, changes from period to period, and potential magnitude. See note 24(c) for details.

(b)Recently issued accounting guidance not yet adopted

The FASB issued ASU 2023-02, Accounting for Investments in Tax Credit Structures Using the Proportional Amortization Method — A Consensus of the Emerging Issues Task Force, which permits a reporting entity, if certain conditions are met, to elect to account for its tax equity investments by using the proportional amortization method regardless of the program from which it receives income tax credits. The amendments in this update are effective for fiscal years beginning after December 15, 2023, including interim periods within those fiscal years. Early adoption is permitted. The Company is currently assessing the applicability and potential impact of the new guidance.

The FASB issued ASU 2023-05, Joint Venture Formations: Recognition and Initial Measurement, which requires a joint venture to recognize and initially measure its assets and liabilities at fair value as at the joint venture formation date. The amendments in this update are effective prospectively for all joint venture formations with a formation date on or after January 1, 2025. Additionally, a joint venture formed before January 1, 2025 may elect to apply the amendments retrospectively if it has sufficient information. Early adoption is permitted. The Company is currently assessing the applicability and potential impact of the new guidance.

The FASB issued ASU 2023-07, Segment Reporting: Improvement to Reportable Segments Disclosures, which requires enhanced disclosures about significant segment expenses. The amendments in this update are effective for annual periods beginning on December 15, 2023 and interim periods within annual periods beginning on December 15, 2024. Early adoption is permitted. The Company is currently assessing the relevant disclosure.

The FASB issued ASU 2023-09, Income Taxes: Improvement to Income Tax Disclosures, which requires a reporting entity to disclose additional income tax information primarily related to the rate reconciliation and income taxes paid information. The amendments in this update are effective prospectively for annual periods beginning on December 15, 2024. Early adoption is permitted. The Company is currently assessing the relevant disclosure.

Notes to the Consolidated Financial Statements 92

Algonquin Power & Utilities Corp.

Notes to the Consolidated Financial Statements

December 31, 2023 and 2022

(in thousands of U.S. dollars, except as noted and per share amounts)

3.Business acquisitions, development projects and disposition transactions

(a)Kentucky Power Company and AEP Kentucky Transmission Company, Inc.

On October 26, 2021, Liberty Utilities Co., an indirect subsidiary of AQN, entered into an agreement (the “Kentucky Acquisition Agreement”) with American Electric Power Company, Inc. (“AEP”) and AEP Transmission Company, LLC to acquire Kentucky Power Company and AEP Kentucky Transmission Company, Inc. (the “Kentucky Power Transaction”). On April 17, 2023, Liberty Utilities Co. mutually agreed with AEP and AEP Transmission Company, LLC to terminate the Kentucky Acquisition Agreement. The Company recognized $46,527 in other net losses for the year ended December 31, 2023 related to a write-off of costs incurred in preparation for the Kentucky Power Transaction and the termination of the Kentucky Acquisition Agreement. See note 19 for details.

(b)Acquisition of the Deerfield II Wind Facility

On June 15, 2023, the Company, acquired the remaining 50% ownership in the Deerfield II Wind Facility for consideration of $23,142. The transaction has been accounted for as an asset acquisition. Subsequent to acquisition, the tax equity investors provided additional funding of $98,955, and a third-party construction loan of $158,550 was repaid.

The following table summarizes the allocation of the aggregate purchase price to the assets acquired and liabilities assumed at the acquisition dates.

	Deerfield II
Working capital	$	(10,709)
Property, plant and equipment	194,419
Long-term debt	(157,935)
Asset retirement obligation	(1,030)
Deferred tax liability	(1,603)
Total net assets acquired	23,142
Cash and cash equivalents	1,662
Net assets acquired, net of cash and cash equivalents	$	21,480

(c)Acquisition of the Sandy Ridge II Wind Facility

Subsequent to year end, on February 15, 2024, the Company acquired the remaining 50% ownership in the Sandy Ridge II Wind Facility for consideration of $8,456. Subsequent to acquisition, the tax equity investors provided additional funding of $60,545, and a third-party construction loan of $162,805 was repaid. Due to the timing of the acquisition, the Company has not completed the fair value measurements. The Company will continue to review information and perform further analysis prior to finalizing the allocation of the consideration paid to the fair value of the assets acquired and liabilities assumed.

(d)Partial disposition of renewable assets

On December 29, 2022, the Company closed the sale of ownership interests in a portfolio of operating wind facilities in the United States and Canada. The transaction consisted of the sale of (1) a 49% ownership interest in three operating wind facilities in the United States totalling 551 MW of installed capacity: the Odell Wind Facility in Minnesota, the Deerfield I Wind Facility in Michigan and the Sugar Creek Wind Facility in Illinois; and (2) an 80% ownership interest in the operating 175 MW Blue Hill Wind Facility in Saskatchewan. The Company retains control over the U.S. facilities. The Company oversees day-to-day operations and provides management services to each of the facilities.

The cash proceeds of $277,500 for the U.S. facilities, which continue to be consolidated, were recorded as non-controlling interest (subject to certain post-closing adjustments). The investment in the Blue Hill Wind Facility continues to be recorded as an equity-method investee. Cash proceeds of C$108,610 were received for the Blue Hill Wind Facility (subject to certain post-closing adjustments). A gain on disposition of $62,828 was recognized and included in gain on sale of renewable assets on the consolidated statements of operations.

Notes to the Consolidated Financial Statements 93

Algonquin Power & Utilities Corp.

Notes to the Consolidated Financial Statements

December 31, 2023 and 2022

(in thousands of U.S. dollars, except as noted and per share amounts)

3.Business acquisitions, development projects and disposition transactions (continued)

(e)Acquisition of New York American Water Company, Inc.

Effective January 1, 2022, the Company completed the acquisition of New York American Water Company, Inc (subsequently renamed Liberty Utilities (New York Water) Corp. (“Liberty NY Water”)). Liberty NY Water is a regulated water and wastewater utility, serving customers in eight counties in southeastern New York.

A purchase price of $609,000 was paid for this acquisition. The acquisition related costs were expensed through the consolidated statement of operations (note 19). The following table summarizes the final allocation of the purchase price to the assets acquired and liabilities assumed when control was obtained.

Working capital	$	4,820
Property, plant and equipment (i)	499,252
Goodwill (ii)	116,254
Regulatory assets (iii)	65,621
Other assets	4,507
Pension and other post-employment benefits	(13,402)
Regulatory liabilities (iii)	(59,727)
Other liabilities	(8,028)
Total net assets acquired	$	609,297
Cash and cash equivalents acquired	49
Total net assets acquired, net of cash and cash equivalents	$	609,248

The determination of the fair value of assets acquired and liabilities assumed is based upon management’s estimates and certain assumptions.

i.Property, plant and equipment consist of regulated water distribution infrastructure and wastewater collection and treatment facilities. They are amortized in accordance with regulatory requirements over the estimated useful life of the assets using the straight-line method. The weighted average useful life of Liberty NY Water’s assets is 64.74 years.

ii.Goodwill represents the excess of the purchase price over the aggregate fair value of net assets acquired. The contributing factors to the amount recorded as goodwill include future growth, potential synergies, and cost of savings in the delivery of certain shared administrative and other services. Goodwill is reported under the Regulated Services Group.

iii.The Company is subject to regulation by the New York State Public Service Commission (“NYPSC”), which has jurisdiction with respect to rates, service, accounting procedures, acquisitions and other matters. Under ASC 980, regulatory assets and liabilities are recorded to the extent that they represent probable future revenue or expenses associated with certain charges or credits that will be recovered from or refunded to customers through the rate making process (note 7). As part of the approval of the acquisition of Liberty NY Water, a settlement agreement was approved which requires a full year of ownership prior to the filing of a new rate case. As a result, new rates would not come into effect until 2024.

Liberty NY Water was consolidated upon acquisition. In 2022, Liberty NY Water generated approximately $125,370 in revenue and $21,776 operating income.

4.Accounts receivable

Accounts receivable as of December 31, 2023 include unbilled revenue of $107,001 (2022 - $149,015) from the Company’s regulated utilities. Accounts receivable as of December 31, 2023 are presented net of allowance for doubtful accounts of $30,244 (2022 - $24,857).

Notes to the Consolidated Financial Statements 94

Algonquin Power & Utilities Corp.

Notes to the Consolidated Financial Statements

December 31, 2023 and 2022

(in thousands of U.S. dollars, except as noted and per share amounts)

5.Property, plant and equipment

Property, plant and equipment consist of the following:

2023
	Cost		Accumulated depreciation		Net book value
Renewable generation facilities	$	4,200,559	$	1,139,137	$	3,061,422
Utility plant	9,332,092		1,191,013		8,141,079
Land	133,483		—		133,483
Equipment	122,929		53,181		69,748
Construction-in-progress
Generation	378,043		—		378,043
Distribution and transmission	733,675		—		733,675
	$	14,900,781	$	2,383,331	$	12,517,450

2022
	Cost		Accumulated depreciation		Net book value
Renewable generation facilities	$	4,119,514	$	1,016,784	$	3,102,730
Utility plant	8,640,224		990,975		7,649,249
Land	113,153		—		113,153
Equipment	111,707		50,904		60,803
Construction-in-progress
Generation	196,287		—		196,287
Distribution and transmission	822,663		—		822,663
	$	14,003,548	$	2,058,663	$	11,944,885

During the fourth quarter of 2022, the Company concluded that some assets in the Renewable Energy Group may not be recoverable due to declining forecasted energy prices in the Electric Reliability Council of Texas (“ERCOT”) market, mainly affecting the results of the Senate Wind Facility (which began commercial operations in 2012). Accordingly, the Company performed fair value analysis based on the income approach and recorded an impairment charge of $159,568 to reduce the carrying value of the Senate Wind Facility and other smaller assets from $259,942 to $100,374.

Renewable generation facilities include cost of $117,556 (2022 - $111,192) and accumulated depreciation of $52,506 (2022 - $46,666) related to facilities under financing lease or owned by consolidated VIEs. Depreciation expense of facilities under finance leases was $537 (2022 - $1,489). Utility plant includes cost of $3,270 (2022 - $3,076) and accumulated depreciation of $2,455 (2022 - $2,041) related to assets under finance lease.

Utility plant includes cost of $1,922,844 (2022 - $2,033,391) and accumulated depreciation of $141,466 (2022 - $133,644) related to regulated generation assets.

For the year ended December 31, 2023, contributions received in aid of construction of $238 (2022 - $1,299) have been credited to the cost of the assets.

Notes to the Consolidated Financial Statements 95

Algonquin Power & Utilities Corp.

Notes to the Consolidated Financial Statements

December 31, 2023 and 2022

(in thousands of U.S. dollars, except as noted and per share amounts)

5.Property, plant and equipment (continued)

Interest and AFUDC capitalized to the cost of the assets in 2023 and 2022 are as follows:

	2023		2022
Interest capitalized on non-regulated property	$	6,374	$	4,762
AFUDC capitalized on regulated property:
Allowance for borrowed funds	8,305		6,040
Allowance for equity funds	3,372		1,901
	$	18,051	$	12,703

6.Intangible assets and goodwill

Intangible assets consist of the following:

2023	Cost		Accumulated amortization		Net book value
Power sales contracts	$	58,200	$	43,938	$	14,262
Customer relationships	77,104		14,625		62,479
Interconnection agreements	10,329		1,977		8,352
Other (a)	10,352		1,507		8,845
	$	155,985	$	62,047	$	93,938

2022	Cost		Accumulated amortization		Net book value
Power sales contracts	$	56,926	$	42,818	$	14,108
Customer relationships	77,850		13,709		64,141
Interconnection agreements	10,098		1,851		8,247
Other (a)	10,338		151		10,187
	$	155,212	$	58,529	$	96,683

(a) Other includes brand names, water rights and miscellaneous intangibles

Estimated amortization expense for intangible assets for each of the next five years is $2,674.

All goodwill pertains to the Regulated Services Group.

	2023		2022
Opening balance	$	1,320,579	$	1,201,244
Business acquisitions	4,195		123,751
Foreign exchange	(712)		(4,416)
Closing balance	$	1,324,062	$	1,320,579

7. Regulatory matters

The operating companies within the Regulated Services Group are subject to regulation by the respective Regulators of the jurisdictions in which they operate. The respective Regulators have jurisdiction with respect to rate, service, issuance of securities, acquisitions and other matters. Except for Suralis, these utilities operate under cost-of-service regulation as administered by these authorities. The Company’s regulated utility operating companies are accounted for under the principles of ASC 980. Under ASC 980, regulatory assets and liabilities that would not be recorded under U.S. GAAP for non-regulated entities are recorded to the extent that they represent probable future revenue or expenses associated with certain charges or credits that will be recovered from or refunded to customers through the rate-setting process.

Notes to the Consolidated Financial Statements 96

Algonquin Power & Utilities Corp.

Notes to the Consolidated Financial Statements

December 31, 2023 and 2022

(in thousands of U.S. dollars, except as noted and per share amounts)

7.Regulatory matters (continued)

At any given time, the Company can have several regulatory proceedings underway. The financial effects of these proceedings are reflected in the consolidated financial statements based on regulatory approval obtained to the extent that there is a financial impact during the applicable reporting period. The following regulatory proceedings were recently completed:

Utility	State, Province or Country	Regulatory Proceeding Type	Details
Apple Valley Water System	California	General rate review	On February 3, 2023, the California Public Utilities Commission (“CPUC”) issued a final order authorizing an annual revenue increase of $1,494. New rates became effective on April 7, 2023 retroactive to July 1, 2022. The retroactive impact of this final order was recorded in the first quarter of 2023.
Park Water System	California	General rate review	On February 3, 2023, the CPUC issued a final order authorizing an annual revenue increase of $1,105. New rates became effective on April 7, 2023 retroactive to July 1, 2022. The retroactive impact of this final order was recorded in the first quarter of 2023.
CalPeco Electric System	California	General rate review	On April 27, 2023, the California Public Utilities Commission (“CPUC”) issued a final order approving a revenue increase of $26,979. New rates became effective on July 1, 2023 retroactive to January 2022. The retroactive impact of this final order was recorded in the second quarter of 2023.
St. Lawrence Gas	New York	General rate review	On June 22, 2023, the New York State Department of Public Services issued an Order authorizing a revenue increase of $5,249 to be implemented over the course of 2023-2025. New rates became effective July 1, 2023.
Pine Bluff Water	Arkansas	General rate review	On August 4, 2023, the Arkansas Public Service Commission issued an Order approving a unanimous settlement agreement filed by the parties authorizing an annual revenue increase of $3,400. New rates became effective August 15, 2023.
Gas New Brunswick	New Brunswick	General rate review	On September 21, 2023 the Energy & Utilities Board issued a decision authorizing a revenue decrease of $700.
Empire Electric	Arkansas	General rate review	On December 7, 2023, the Arkansas Public Service Commission issued an Order approving the settlement agreement authorizing a revenue increase of $5,300. New rates became effective January 1, 2024.
Empire Electric	Missouri	Securitization	On August 1, 2023, the Missouri Western District Court of Appeals affirmed the amount eligible for securitization in line with the Missouri Public Service Commission’s (“MPSC”) order of $290,383. Subsequent to year-end, on January 30, 2024. the Company completed the securitization to recover the costs associated with the extreme winter storm conditions experienced in Texas and parts of central U.S in February 2021 (“Midwest Extreme Weather Event”) and the remaining book value of the Asbury generating plant. The MPSC’s order excludes a portion of carrying costs and taxes associated with the retirement of the Asbury plant. Thus. the Company has incurred a one-time net loss of $63,495 ($48,452 net of tax) in the third quarter of 2023.

Notes to the Consolidated Financial Statements 97

Algonquin Power & Utilities Corp.

Notes to the Consolidated Financial Statements

December 31, 2023 and 2022

(in thousands of U.S. dollars, except as noted and per share amounts)

7.Regulatory matters (continued)

Regulatory assets and liabilities consist of the following:

	December 31, 2023		December 31, 2022
Regulatory assets
Fuel and commodity cost adjustments (a)	$	326,418	$	388,294
Retired generating plant (b)	183,732		174,609
Rate adjustment mechanism (c)	192,880		136,198
Income taxes (d)	101,939		97,414
Deferred capitalized costs (e)	124,517		90,121
Pension and post-employment benefits (f)	68,822		80,736
Environmental remediation (g)	66,779		70,529
Wildfire mitigation and vegetation management (h)	64,146		66,156
Clean energy and other customer programs (i)	37,214		28,145
Asset retirement obligation (j)	26,620		27,172
Debt premium (k)	18,995		24,888
Cost of removal (l)	11,084		11,084
Rate review costs (m)	8,815		9,481
Long-term maintenance contract (n)	4,932		6,504
Other regulatory assets (o)	90,790		60,170
Total regulatory assets	$	1,327,683	$	1,271,501
Less: current regulatory assets	(142,970)		(190,393)
Non-current regulatory assets	$	1,184,713	$	1,081,108
Regulatory liabilities
Income taxes (d)	$	290,121	$	312,671
Cost of removal (l)	185,786		191,173
Pension and post-employment benefits (f)	104,636		68,085
Fuel and commodity cost adjustments (a)	42,850		24,991
Clean energy and other customer programs (i)	12,730		11,572
Rate adjustment mechanism (c)	2,078		343
Other regulatory liabilities (p)	96,095		19,347
Total regulatory liabilities	$	734,296	$	628,182
Less: current regulatory liabilities	(99,850)		(69,865)
Non-current regulatory liabilities	$	634,446	$	558,317

As recovery of regulatory assets is subject to regulatory approval, if there were any changes in regulatory positions that indicate recovery is not probable, the related cost would be charged to earnings in the period of such determination. The Company generally does not earn a return on the regulatory balances except for carrying charges on fuel and commodity cost adjustments (a), rate adjustment mechanism (c), clean energy and other customer programs (i), and rate review costs of some jurisdictions (m). During 2023, the Company recognized $41,410 (2022 - $18,179) of carrying charges on regulatory balances on the consolidated statements of operations under other income and was computed using only the debt component of the allowed returned.

Notes to the Consolidated Financial Statements 98

Algonquin Power & Utilities Corp.

Notes to the Consolidated Financial Statements

December 31, 2023 and 2022

(in thousands of U.S. dollars, except as noted and per share amounts)

7.Regulatory matters (continued)

(a)Fuel and commodity cost adjustments

The revenue from the utilities includes a component that is designed to recover the cost of electricity and natural gas through rates charged to customers. To the extent actual costs of power or fuel purchased differ from power or fuel costs recoverable through current rates, that difference is deferred and recorded as a regulatory asset or liability on the consolidated balance sheets. These differences are reflected in adjustments to rates and recorded as an adjustment to cost of electricity and fuel in future periods ranging mostly from 6 to 24 months, subject to regulatory review. Derivatives are often utilized to manage the price risk associated with natural gas purchasing activities in accordance with the expectations of state regulators. The gains and losses associated with these derivatives (note 24(b)(i)) are recoverable through the commodity costs adjustment.

In February 2021, the Company’s operations were impacted by the Midwest Extreme Weather Event. As a result of the Midwest Extreme Weather Event, the Company incurred incremental commodity costs during the period of record high pricing and elevated consumption. The Company has commodity cost mechanisms that allow for the recovery of prudently incurred expenses.

In early 2022, pursuant to the securitization statute, Empire Electric sought authorization for the issuance of $221,646 in securitized utility tariff bonds associated with the Midwest Extreme Weather Event and $140,774, in securitized utility tariff bonds for its Asbury costs, which included $21,283 in asset retirement obligations, which are estimates of costs that Empire Electric will recover from the Asbury retirement but which have not yet been incurred. On August 1, 2023, the Missouri Western District Court of Appeals affirmed the amount eligible for securitization in line with the MPSC’s order of $290,383. The MPSC’s order excludes a portion of carrying costs and taxes associated with the retirement of the Asbury plant. Thus, the Company has incurred a one-time net loss of $63,495 ($48,452 net of tax) in the third quarter of 2023.

Subsequent to year-end, on January 30, 2024, Empire District Bondco, LLC, a wholly owned subsidiary of The Empire District Electric Company, completed an offering of approximately $180.5 million of aggregate principal amount of 4.943% Securitized Utility Tariff Bonds with a maturity date of January 1, 2035 and $125 million aggregate principal amount of 5.091% Securitized Utility Tariff Bonds with a maturity date of January 1, 2039, to recover previously incurred qualified extraordinary costs associated with the Midwest Extreme Weather Event and energy transition costs related to the retirement of the Asbury generating plant.

(b)Retired generating plant

On March 1, 2020, the Company’s 200 MW coal generation facility located in Asbury, Missouri, ceased operations. The Company transferred the remaining net book value of Asbury’s plant retired from plant in-service to a regulatory asset. The net book value that may be retained as an asset on the consolidated balance sheets for the retired plant is dependent upon amounts that may be recovered through regulated rates, including any return. An impairment charge, if any, would equal the difference between the remaining net book value of the asset and the present value of the future revenues expected from the asset. The Company is also assessing the decommissioning requirements associated with the retirement of the facility.

Per commission orders in its jurisdictions, the Company is required to track the impact of Asbury's retirement on operating and capital expenses in Missouri for consideration in the next rate case. The Company recorded a regulatory liability for the estimated amount of revenues collected from customers for Asbury from March 1, 2020 to May 1, 2022 that AQN determined was probable of refund. This regulatory liability did not include revenues collected related to the return on investment in Asbury as AQN determined that they were not probable of refund to customers based on the relevant facts and circumstances. The Asbury regulatory liability will be offset for recovery purposes against its unrecovered investment in Asbury and as a result, the regulatory liability is netted against its retired generation facilities regulatory asset.

Notes to the Consolidated Financial Statements 99

Algonquin Power & Utilities Corp.

Notes to the Consolidated Financial Statements

December 31, 2023 and 2022

(in thousands of U.S. dollars, except as noted and per share amounts)

7.Regulatory matters (continued)

(b)Retired generating plant (continued)

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. As noted above under (a) Fuel and commodity cost adjustments, subsequent to year-end, on January 30, 2024, the Company completed the securitization of the costs associated with the retirement of the Asbury plant in accordance with the MPSC’s order.

(c)Rate adjustment mechanism

Revenue for CalPeco Electric System, New England Gas System, Midstates Gas system, EnergyNorth Gas System, Granite State Electric System, Peach State Gas System and BELCO is subject to a revenue decoupling mechanism approved by their respective regulator, which allows revenue decoupling from sales. As a result, the difference between delivery revenue calculated based on metered consumption and approved delivery revenue is recorded as a regulatory asset or liability to reflect future recovery or refund, respectively, from customers over periods ranging from one to five years. The revenue from BELCO includes a component that is designed to recover budgeted capital and operating expenses for the current year. To the extent actual capital and operating expenditures are lower than the budgeted amounts, 80% of the shortfall is refundable to customers and is recorded as a regulatory liability. Retroactive rate adjustments for services rendered but to be collected over a period not exceeding 24 months are accrued upon approval of the final order. The difference between New Brunswick Gas’ regulated revenues and its regulated cost of service in past years is also recorded as a regulatory asset and is recovered on a straight-line basis over 26 years. The Liberty NY Water System has similar trackers, which are recovered over periods ranging from one to two years.

(d)Income taxes

The income taxes regulatory assets and liabilities represent income taxes recoverable through future revenues required to fund flow-through deferred income tax liabilities over the life of the plants and amounts owed to customers for deferred taxes collected at a higher rate than the current statutory rates.

(e)Deferred capitalized costs

Deferred capitalized costs reflect deferred construction costs and fuel-related costs of specific generating facilities of the Empire Electric System. These amounts are being recovered over the life of the plants. The amount also includes capitalized operating and maintenance costs of New Brunswick Gas, and these amounts are being recovered at a rate of 2.43% annually.

In 2020, the Empire Electric System made an election under Missouri law to apply the plant-in-service accounting (“PISA”) regulatory mechanism, which permits the Empire Electric System to defer, on a Missouri jurisdictional basis, 85% of the depreciation expense and carrying costs at the applicable weighted average cost of capital (“WACC”) on certain property, plant and equipment placed in service after the election date and not included in base rates. The portions of regulatory asset balances that are not yet being recovered through rates shall include carrying costs at the WACC, plus applicable federal, state and local income or excise taxes. Regulatory asset balances included in rate base shall be recovered in rates through a 20-year amortization beginning on the effective date of new rates. The Company recognizes the cost of debt on PISA deferrals as reduction of interest expense. The difference between the WACC and cost of debt will be recognized in revenue when recovery of such deferrals is reflected in customer rates.

Notes to the Consolidated Financial Statements 100

Algonquin Power & Utilities Corp.

Notes to the Consolidated Financial Statements

December 31, 2023 and 2022

(in thousands of U.S. dollars, except as noted and per share amounts)

7.Regulatory matters (continued)

(f)Pension and post-employment benefits

To the extent pension and OPEB costs incurred differ from the costs recoverable through current rates, that difference is deferred and recorded as a regulatory asset or liability as approved by the applicable Regulators and is recovered through rates over a period of three to eight years. In addition, the annual movements in AOCI for pension and OPEB for Empire Electric System, Empire Gas Systems, St. Lawrence Gas System and Liberty NY Water System (note 10(a)) are reclassified to regulatory accounts in accordance with ASC 980. The balance is recovered through rates consistent with the treatment of OCI under ASC 712, Compensation Non-retirement Post-employment Benefits and ASC 715, Compensation Retirement Benefits. As part of certain business acquisitions, the regulators authorized a regulatory asset or liability being set up for the amounts of pension and post-employment benefits that had not yet been recognized in net periodic cost and were presented as AOCI prior to the acquisition. These balances are recovered through rates over the future service years of the employees (an average of 10 years) or consistent with the treatment of OCI under ASC 712, Compensation Non-retirement Post-employment Benefits and ASC 715, Compensation Retirement Benefits before the transfer to regulatory asset occurred.

(g)Environmental remediation

Actual expenditures incurred for the clean-up of certain former natural gas manufacturing facilities (note 12(d)) are recovered through rates over a period of seven years and are subject to an annual cap.

(h)Wildfire mitigation and vegetation management

The regulatory asset includes incremental wildfire liability insurance premium costs approved for tracking in the Company’s California operations as well as the difference between actual and adopted spending related to dead trees program, to prevent future forest fires and general vegetation management. The assets are recovered over two years.

(i)Clean energy and other customer programs

The regulatory asset for clean energy and customer programs includes initiatives related to solar rebate applications processed and resulting rebate-related costs. The amount also includes other energy efficiency programs. The assets are generally included in rate base and recovered over periods of six to ten years.

(j)Asset retirement obligation

Asset retirement obligations are recorded for legally required removal costs of property, plant and equipment. The costs of retirement of assets as well as the on-going liability accretion and asset depreciation expense are expected to be recovered through rates once expenditures are made.

(k)Debt premium

Debt premium on acquired debt is recovered as a component of the weighted average cost of debt.

(l)Cost of removal

Rates charged to customers cover for costs that are expected to be incurred in the future to retire the utility plant. A regulatory liability (or asset) tracks the amounts that have been collected from customers net of costs incurred to date.

(m)Rate review costs

The cost to file, prosecute and defend rate review applications is referred to as rate review costs. These costs are capitalized and amortized over the period of rate recovery granted by the Regulator ranging from one to five years

(n)Long-term maintenance contract

To the extent actual costs of long-term maintenance incurred for one of Empire Electric System's power plants differ from the costs recoverable through current rates, that difference is generally included in rate base and recovered over five years.

(o)Other regulatory assets

The Company’s regulated utilities incur other miscellaneous costs such as storm costs, property taxes, financing costs and equipment costs, which are probable of recovery under existing mechanisms.

Notes to the Consolidated Financial Statements 101

Algonquin Power & Utilities Corp.

Notes to the Consolidated Financial Statements

December 31, 2023 and 2022

(in thousands of U.S. dollars, except as noted and per share amounts)

7.Regulatory matters (continued)

(p)Other regulatory liabilities

During the year, the Company recognized a regulatory liability of $63,495 relating to the portion of additional securitization costs of Empire Electric that were not allowed as per the Securitization Statute.

8.Long-term investments

Long-term investments consist of the following:

	December 31, 2023		December 31, 2022
Long-term investments carried at fair value
Atlantica (a)	$	1,052,703	$	1,268,140
Atlantica Yield Energy Solutions Canada Inc. (b)	61,064		74,083
Other	1,962		1,984
	$	1,115,729	$	1,344,207
Other long-term investments
Equity-method investees (c)	$	456,393	$	381,802
Development loans receivable from equity-method investees (d)	158,110		52,923
San Antonio Water System and other (e)	27,417		27,600
	$	641,920	$	462,325

Fair value change, income (loss) and impairment expense related to long-term investments from the years ended December 31 is as follows:

	Year ended December 31,
	2023		2022
Fair value loss on investments carried at fair value
Atlantica	$	(215,437)	$	(482,774)
Atlantica Yield Energy Solutions Canada Inc.	(14,684)		(16,018)
Other	133		(333)
	$	(229,988)	$	(499,125)
Dividend and interest income from investments carried at fair value
Atlantica	$	87,154	$	86,664
Atlantica Yield Energy Solutions Canada Inc.	16,604		20,443
Other	49		36
	$	103,807	$	107,143
Other long-term investments
Equity method loss (c)	$	(5,936)	$	(21,416)
Impairment of equity-method investee (c)	—		(75,910)
Interest and other income	7,143		5,923
	$	1,207	$	(91,403)
Fair value change, income (loss) and impairment expense related to long-term investments	$	(124,974)	$	(483,385)

Notes to the Consolidated Financial Statements 102

Algonquin Power & Utilities Corp.

Notes to the Consolidated Financial Statements

December 31, 2023 and 2022

(in thousands of U.S. dollars, except as noted and per share amounts)

8.Long-term investments (continued)

(a)Investment in Atlantica

Liberty (AY Holdings) B.V. (“AY Holdings”), an entity controlled and consolidated by AQN, has a share ownership in Atlantica Sustainable Infrastructure PLC (“Atlantica”) of approximately 42% (2022 - 42%). AQN has the flexibility, subject to certain conditions, to increase its ownership of Atlantica up to 48.5%. The total cost for the Atlantica shares as of December 31, 2023 is $1,167,444 (2022 - $1,167,444).

The Company has elected the fair value option under ASC 825, Financial Instruments to account for its investment in Atlantica, with changes in fair value reflected in the consolidated statements of operations.

(b)Investment in Atlantica Yield Energy Solutions Canada Inc.

AQN and Atlantica own Atlantica Yield Energy Solutions Canada Inc. (“AYES Canada”), a vehicle to channel co-investment opportunities in which Atlantica holds the majority of voting rights. AYES Canada invested in Windlectric Inc. (“Windlectric”). The investmentby AYES Canada in Windlectric is presented as a non-controlling interest held by a related party.

AYES Canada is considered to be a VIE based on the disproportionate voting and economic interests of the shareholders. Atlantica is considered to be the primary beneficiary of AYES Canada. Accordingly, AQN's investment in AYES Canada is considered an equity-method investment. Under the AYES Canada shareholders agreement, AQN has the option to exchange approximately 3,500,000 shares of AYES Canada into ordinary shares of Atlantica on a one-for-one basis, subject to certain conditions. Consistent with the treatment of the Atlantica shares, the Company has elected the fair value option under ASC 825, Financial Instruments to account for its investment in AYES Canada, with changes in fair value reflected in the consolidated statements of operations.

As of December 31, 2023, the Company's maximum exposure to loss is $61,064 (2022 - $74,083), which represents the fair value of the investment.

(c)Equity-method investees

The Renewable Energy Group has non-controlling interests in operating renewable energy facilities and projects under construction with a total carrying value of $343,712 (2022 - $310,103). The Regulated Services Group has non-controlling interest of $112,180 (2022 - $56,199) in a power transmission line project under construction and other non-regulated operating entities owned by its utilities. The Liberty Development JV Inc. platform for non-regulated renewable energy, water and other sectors has a carrying value of $501 and (2022 - $15,500) is reported under Corporate.

Operating entities: The Company has interests in the operating entities listed below. The Company is not considered the primary beneficiary as the two partners have joint control and all key decisions must be unanimous. As such, the Company accounts for its interests using the equity method.

	Economic interest		Capacity
Texas Coastal Wind Facilities	51	%	861 MW
Blue Hill Wind Facility	20	%	175 MW
Red Lily Wind Facility	75	%	26.4 MW
Val-Eo Wind Facility	50	%	24 MW

During 2021, the Company acquired a 51% interest in four wind facilities located in Texas (“Texas Coastal Wind Facilities”) for $344,883. All facilities achieved commercial operations in 2021. During the fourth quarter of 2022, the Company concluded that primarily as a result of continued challenges with congestion at the facilities, the carrying value of the interest in the Texas Coastal Wind Facilities was other-than-temporarily impaired. Accordingly, the Company performed a fair value analysis based on the income approach and recorded an impairment charge of $75,910 to reduce the carrying value of its equity investment in the Texas Coastal Wind Facilities from $282,726 to $206,816. Changes in assumptions of revenue forecasts, driven by expected production, basis difference and resulting spot prices, projected operating and capital expenditures would affect the estimated fair value.

Notes to the Consolidated Financial Statements 103

Algonquin Power & Utilities Corp.

Notes to the Consolidated Financial Statements

December 31, 2023 and 2022

(in thousands of U.S. dollars, except as noted and per share amounts)

8.Long-term investments (continued)

(c)Equity-method investees (continued)

As at December 31, 2023, the Company has issued $113,630 (2022 - $113,630) in letters of credit and guarantees of performance obligations under energy purchase agreements and decommissioning obligations on behalf of the Texas Coastal Wind Facilities.

Development: Pursuant to an agreement between AQN and funds managed by the Infrastructure and Power strategy of Ares Management, LLC (“Ares”), in November 2021 Ares became AQN’s new partner in its non-regulated development platform for renewable energy, water and other sectors as both parties contributed cash or assets of $19,688 to Liberty Development JV Inc. The Company is not considered the primary beneficiary as the two partners have joint control and all key decisions must be unanimous. As such, the Company accounts for its interests using the equity method.

On July 5, 2023, the Company provided a $35,000 non-interest-bearing loan to Liberty Development JV Inc. The joint venture used these funds to return equity to its shareholders through which the Company received $17,500. Further, the Company recognized an impairment loss on its note receivable of $18,911 as it no longer expects to pursue development under this joint venture arrangement and the development fees are no longer expected to be realized. The impairment is recorded within asset impairment charge in the consolidated statements of operations. Subsequent to year-end, on January 4, 2024, the Company purchased Ares’ 50% interest in Liberty Development JV Inc. and Liberty Development Energy Solutions B.V.

Construction: The Renewable Energy Group has 50% equity interests in several wind and solar power electric construction projects. AQN and Ares have formed Liberty Construction (US) JV LLC (“Liberty Construction JV”) to jointly construct projects under the Renewable Energy Group. During the year, the Company contributed several projects to joint entities. The Company holds an option to acquire the remaining interest in most construction projects at a pre-agreed price. The Company is not considered the primary beneficiary as the partners have joint control and all key decisions must be unanimous. As such, the Company accounts for its interests using the equity method.

Changes in the carrying value of equity method investees were as follows:

	2023		2022
Carrying value, January 1	$	381,802	$	433,850
Additional investments	91,205		110,441
Net loss attributable to AQN	(5,936)		(21,416)
OCI attributable to AQN (a)	7,693		(67,110)
Dividend received	(4,600)		(1,183)
Impairment	—		(75,910)
Other	(13,771)		3,130
Carrying value, December 31	$	456,393	$	381,802

(a)OCI represents the Company’s proportion of the change in fair value, recorded in OCI at the investee level, on energy derivative financial instruments designated as a cash flow hedge

Notes to the Consolidated Financial Statements 104

Algonquin Power & Utilities Corp.

Notes to the Consolidated Financial Statements

December 31, 2023 and 2022

(in thousands of U.S. dollars, except as noted and per share amounts)

8.Long-term investments (continued)

(c)Equity-method investees (continued)

Summarized combined information for AQN's equity method investees as of December 31 is as follows:

	2023		2022
Total assets	$	3,235,474	$	2,740,132
Total liabilities	1,962,115		1,507,079
Net assets	1,273,359		1,233,053
AQN's ownership interest in the entities	388,993		332,663
Difference between investment carrying amount and underlying equity in net assets(a)	67,400		49,139
Total carrying value	$	456,393	$	381,802

(a) The difference between the investment carrying amount and the underlying equity in net assets relates primarily to interest capitalized while the projects are under construction, the fair value of guarantees provided by the Company in regards to the investments, development fees and transaction costs.

Summarized combined information for AQN's equity method investees for the year ended December 31 (presented at 100%) is as follows:

	2023		2022
Revenue	$	111,446	$	65,025
Net loss	$	(3,633)	$	(31,070)
OCI (a)	$	12,026	$	(130,729)
Net loss attributable to AQN	$	(5,936)	$	(21,416)
OCI attributable to AQN (a)	$	7,693	$	(67,110)

(a)OCI represents the Company’s proportion of the change in fair value, recorded in OCI at the investee level, on energy derivative financial instruments designated as a cash flow hedge

Except for Liberty Global Energy Solutions B.V. (formerly Abengoa-Algonquin Global Energy Solutions B.V.) (“Liberty Global Energy Solutions”), Liberty Development JV Inc. and all construction projects are considered VIEs due to the level of equity at risk and the disproportionate voting and economic interests of the shareholders. The Company has committed loan and credit support facilities with some of its equity investees. During construction, the Company has agreed to provide cash advances and credit support for the continued development and construction of the equity investees' projects. As of December 31, 2023, the Company has issued letters of credit and guarantees of performance obligations: under a security of performance for a development opportunity; wind turbine or solar panel supply agreements; engineering, procurement, and construction agreements; interconnection agreements; energy purchase agreements; renewable energy credit agreements; and construction loan agreements. The fair value of the support provided recorded as of December 31, 2023 amounts to $12,666 (2022 - $8,824).

Notes to the Consolidated Financial Statements 105

Algonquin Power & Utilities Corp.

Notes to the Consolidated Financial Statements

December 31, 2023 and 2022

(in thousands of U.S. dollars, except as noted and per share amounts)

8.Long-term investments (continued)

(c)Equity-method investees (continued)

Summarized combined information for AQN's VIEs as of December 31 is as follows:

	2023		2022
AQN's maximum exposure in regards to VIEs
Carrying amount	$	179,728	$	122,752
Development loans receivable (d)	158,110		52,923
Indirect guarantees of debt on behalf of VIEs	740,866		436,790
Other indirect guarantees and commitments on behalf of VIEs	303,641		221,433
	$	1,382,345	$	833,898

The commitments are presented on a gross basis assuming no recoverable value in the assets of the VIEs. The majority of the amounts committed on behalf of VIEs in the above relate to wind turbine or solar panel supply agreements as well as engineering, procurement, and construction agreements.

(d)Development loans receivable from equity investees

The Renewable Energy Group has committed loan and credit support facilities with some of its equity investees. During construction, the Company has agreed to provide cash advances and credit support (in the form of letters of credit, escrowed cash, guarantees or indemnities) in amounts necessary for the continued development and construction of the equity investees' projects. The loans generally mature on the twelfth anniversary of the development agreement or commercial operation date.

(e)San Antonio Water System and other

The Company does not have significant influence over San Antonio Water System investments. It is accounted for using the cost method and as at December 31, 2023, it is recorded at the cost of $25,634 (2022 - $25,634).

Notes to the Consolidated Financial Statements 106

Algonquin Power & Utilities Corp.

Notes to the Consolidated Financial Statements

December 31, 2023 and 2022

(in thousands of U.S. dollars, except as noted and per share amounts)

9.Long-term debt

Long-term debt consists of the following:

Borrowing type	Weighted average coupon		Maturity	Par value		December 31, 2023		December 31, 2022
Senior unsecured revolving credit facilities (a)	—		2024-2028	N/A		$	1,624,186	$	351,786
Senior unsecured bank credit facilities and delayed draw term facility (b)	—		2024-2031	N/A		786,962		773,643
Commercial paper	—		2024	N/A		481,720		407,000
U.S. dollar borrowings
Senior unsecured notes (Green Equity Units)	1.18	%	2026	$	1,150,000	1,144,897		1,142,814
Senior unsecured notes (c)	3.36	%	2024-2047	$	1,415,000	1,406,278		1,496,101
Senior unsecured utility notes	6.30	%	2025-2035	$	137,000	147,589		154,271
Senior secured utility bonds (d)	4.71	%	2026-2044	$	556,199	551,166		554,822
Canadian dollar borrowings
Senior unsecured notes (e)	3.68	%	2027-2050	C$	1,200,000	904,604		882,899
Senior secured project notes	10.21	%	2027	C$	16,848	12,738		15,024
Chilean Unidad de Fomento borrowings
Senior unsecured utility bonds	3.90	%	2028-2040	CLF	1,521	70,967		77,206
						$	7,131,107	$	5,855,566
Subordinated borrowings
Subordinated unsecured notes (f)	5.25	%	2082	C$	400,000	298,382		291,238
Subordinated unsecured notes (f)	5.21	%	2079-2082	$	1,100,000	1,086,541		1,365,213
						$	8,516,030	$	7,512,017
Less: current portion						(621,856)		(423,274)
						$	7,894,174	$	7,088,743

Short-term obligations of $766,886 that are expected to be refinanced using the long-term credit facilities are presented as long-term debt.

Long-term debt issued at a subsidiary level (project notes or utility bonds) relating to a specific operating facility is generally collateralized by the respective facility with no other recourse to the Company. Long-term debt issued at a subsidiary level whether or not collateralized generally has certain financial covenants, which must be maintained on a quarterly basis. Non-compliance with the covenants could restrict cash distributions/dividends to the Company from the specific facilities.

Notes to the Consolidated Financial Statements 107

Algonquin Power & Utilities Corp.

Notes to the Consolidated Financial Statements

December 31, 2023 and 2022

(in thousands of U.S. dollars, except as noted and per share amounts)

9.Long-term debt (continued)

The following table sets out the bank credit facilities available to AQN and its operating groups as of December 31, 2023:

	December 31, 2023		December 31, 2022
Revolving and term credit facilities	$	4,562,000	$	4,513,300
Funds drawn on facilities/commercial paper issued	(2,892,900)		(1,532,500)
Letters of credit issued	(469,100)		(465,200)
Liquidity available under the facilities	1,200,000		2,515,600
Undrawn portion of uncommitted letter of credit facilities	(254,100)		(226,900)
Cash on hand	56,142		57,623
Total liquidity and capital reserves	$	1,002,042	$	2,346,323

Recent financing activities:

(a)Senior unsecured revolving credit facilities

Corporate

On March 31, 2023, the Company's senior unsecured revolving credit facility was amended and restated to increase the borrowing capacity from $500,000 to $1,000,000 with a new maturity date of March 31, 2028.

On March 31, 2023, the Company entered into a new $75,000 uncommitted bi-lateral credit facility.

On June 1, 2023, the Company terminated its former $50,000 uncommitted bi-lateral credit facility.

Regulated Services Group

On October 27, 2023, the Company extended the maturity date of the senior unsecured revolving credit facility of $500,000 from February 28, 2024 to October 25, 2024.

(b)Senior unsecured bank credit facilities and delayed draw term facilities

On April 25, 2023, the Regulated Services Group elected to terminate the undrawn amount of $489,600 of its $1,100,000 senior unsecured syndicated delayed draw term facility (the “Regulated Services Delayed Draw Term Facility”), which was intended to be used to partially fund the Kentucky Power Transaction. On October 27, 2023, the Company extended the maturity of the Regulated Services Delayed Draw Term Facility of $610,400 from November 29, 2023 to October 25, 2024.

(c)Senior unsecured notes

On March 13, 2023, the Company repaid a $15,000 senior unsecured note on its maturity.

On July 31, 2023, the Company repaid a $75,000 senior unsecured note on its maturity.

Subsequent to year-end, on January 12, 2024, Liberty Utilities Co., completed an offering of $500,000 aggregate principal amount of 5.577% senior notes due January 31, 2029 (the “2029 Notes”); and $350,000 aggregate principal amount of 5.869% senior notes due January 31, 2034 (the “2034 Notes” and together with the 2029 Notes, the “Senior Notes”). The Senior Notes are unsecured and unsubordinated obligations of Liberty Utilities Co. and rank equally with all of Liberty Utilities Co.’s existing and future unsecured and unsubordinated indebtedness and senior in right of payment to any existing and future Liberty Utilities Co.’s subordinated indebtedness. The 2029 Notes were priced at an issue price of 99.996% of their face value and the 2034 Notes were priced at an issue price of 99.995% of their face value. Liberty Utilities Co. used the net proceeds from the sale of the Senior Notes to repay indebtedness.

Notes to the Consolidated Financial Statements 108

Algonquin Power & Utilities Corp.

Notes to the Consolidated Financial Statements

December 31, 2023 and 2022

(in thousands of U.S. dollars, except as noted and per share amounts)

9.Long-term debt (continued)

(d)Senior unsecured utility bonds

Subsequent to the year-end, on January 30, 2024, Empire District Bondco, LLC, a wholly owned subsidiary of The Empire District Electric Company, completed an offering of approximately $180,500 of aggregate principal amount of 4.943% Securitized Utility Tariff Bonds with a maturity date of January 1, 2035 and $125,000 aggregate principal amount of 5.091% Securitized Utility Tariff Bonds with a maturity date of January 1, 2039, to recover previously incurred qualified extraordinary costs associated with the Midwest Extreme Weather Event and energy transition costs related to the retirement of the Asbury generating plant described in note 7.

(e)Senior unsecured utility notes

On November 1, 2023, the Company repaid a $5,000 senior unsecured utility note on its maturity.

(f)Subordinated unsecured notes

On November 6, 2023, the Company redeemed all $287,500 of its 6.875% fixed-to-floating subordinated notes - series 2018 - at a redemption price equal to 100% of the principal amount, together with accrued and unpaid interest.

As of December 31, 2023, the Company has accrued $74,493 in interest expense (2022 - $70,274). Interest expense for the year ended December 31 consists of the following:

	2023		2022
Long-term debt	$	251,539	$	258,084
Commercial paper, credit facility draws and related fees	134,678		46,466
Accretion of fair value adjustments	(23,834)		(16,547)
Capitalized interest and AFUDC capitalized on regulated property	(14,679)		(10,802)
Other	5,952		1,373
	$	353,656	$	278,574

Principal payments due in the next five years and thereafter are as follows:

2024		2025		2026		2027		2028		Thereafter		Total
$	621,856	$	140,241	$	1,193,531	$	1,280,846	$	819,122	$	4,481,961	$	8,537,557

10.Pension and other post-employment benefits

The Company provides defined contribution pension plans to substantially all of its employees. The Company’s contributions for 2023 were $14,521 (2022 - $12,126).

The Company provides a defined benefit cash balance pension plan under which employees are credited with a percentage of base pay plus a prescribed interest rate credit. In conjunction with the utility acquisitions, the Company also assumes defined benefit pension, SERP and OPEB plans for qualifying employees in the related acquired businesses. The legacy plans are non-contributory defined pension plans covering substantially all employees of the acquired businesses. Benefits are based on each employee’s years of service and compensation. The Company permanently freezes the accrual of benefits for participants in legacy plans. Thereafter, employees accrue benefits under the Company’s cash balance plan. The OPEB plans provide health care and life insurance coverage to eligible retired employees. Eligibility is based on age and length of service requirements and, in most cases, retirees must cover a portion of the cost of their coverage.

Notes to the Consolidated Financial Statements 109

Algonquin Power & Utilities Corp.

Notes to the Consolidated Financial Statements

December 31, 2023 and 2022

(in thousands of U.S. dollars, except as noted and per share amounts)

10.Pension and other post-employment benefits (continued)

(a)Net pension and OPEB obligation

The following table sets forth the projected benefit obligations, fair value of plan assets, and funded status of the Company’s plans as of December 31:

	Pension benefits				OPEB
	2023		2022		2023		2022
Change in projected benefit obligation
Projected benefit obligation, beginning of year	$	628,135	$	765,618	$	217,330	$	292,646
Projected benefit obligation assumed from business combination	—		87,933		—		5,195
Plan settlements	(3,226)		(112)		—		—
Service cost	11,954		16,309		3,253		6,277
Interest cost	33,687		24,787		11,510		9,146
Actuarial loss (gain)	20,172		(198,074)		(10,913)		(82,991)
Contributions from retirees	—		—		2,189		2,220
Plan amendments	—		—		—		(2,452)
Medicare Part D	—		—		355		367
Benefits paid	(42,801)		(68,197)		(14,226)		(13,078)
Foreign exchange	(53)		(129)		—		—
Projected benefit obligation, end of year	$	647,868	$	628,135	$	209,498	$	217,330
Change in plan assets
Fair value of plan assets, beginning of year	569,255		648,864		172,167		192,375
Plan assets acquired in business combination	—		74,532		—		8,577
Actual return on plan assets	65,272		(109,118)		22,620		(30,105)
Employer contributions	22,326		23,296		10,677		11,811
Plan settlements	(3,226)		(112)		—		—
Contributions from retirees	—		—		2,189		2,220
Medicare Part D subsidy receipts	—		—		355		367
Benefits paid	(42,801)		(68,197)		(14,226)		(13,078)
Foreign exchange	2		(10)		—		—
Fair value of plan assets, end of year	$	610,828	$	569,255	$	193,782	$	172,167
Unfunded status	$	(37,040)	$	(58,880)	$	(15,716)	$	(45,163)
Amounts recognized in the consolidated balance sheets consist of:
Non-current assets (note 11)	12,598		12,264		35,879		14,218
Current liabilities	(1,416)		(1,907)		(3,164)		(3,039)
Non-current liabilities	(48,222)		(69,237)		(48,431)		(56,342)
Net amount recognized	$	(37,040)	$	(58,880)	$	(15,716)	$	(45,163)

The accumulated benefit obligations for the pension and OPEB plans are $827,559 and $815,589 as of December 31, 2023 and 2022, respectively.

Notes to the Consolidated Financial Statements 110

Algonquin Power & Utilities Corp.

Notes to the Consolidated Financial Statements

December 31, 2023 and 2022

(in thousands of U.S. dollars, except as noted and per share amounts)

10.Pension and other post-employment benefits (continued)

(a)Net pension and OPEB obligation (continued)

Information for pension and OPEB plans with an accumulated benefit obligation in excess of plan assets:

	Pension				OPEB
	2023		2022		2023		2022
Accumulated benefit obligation	$	425,842	$	413,041	$	71,089	$	198,463
Fair value of plan assets	$	393,857	$	364,229	$	18,793	$	139,368

Information for pension and OPEB plans with a projected benefit obligation in excess of plan assets:

	Pension				OPEB
	2023		2022		2023		2022
Projected benefit obligation	$	507,612	$	489,140	$	71,089	$	198,463
Fair value of plan assets	$	458,497	$	417,994	$	18,793	$	139,368

(b)Pension and post-employment actuarial changes

Change in AOCI, before tax	Pension				OPEB
	Actuarial losses (gains)		Past service losses (gains)		Actuarial losses (gains)		Past service losses (gains)
Balance, January 1, 2022	$	15,807	$	(4,195)	$	(15,630)	$	310
Additions to AOCI	(47,473)		—		(41,527)		(24)
Amortization in current period	(3,429)		1,584		56		(2,476)
Amortization due to plan settlements	15		—		—		—
Reclassification to regulatory accounts	34,409		(752)		23,551		—
Balance, December 31, 2022	$	(671)	$	(3,363)	$	(33,550)	$	(2,190)
Additions to AOCI	(12,600)		—		(23,797)		853
Amortization in current period	617		1,491		2,554		—
Recognition of settlement gain	235		—		—		—
Reclassification to regulatory accounts	5,517		(755)		19,518		—
Balance, December 31, 2023	$	(6,902)	$	(2,627)	$	(35,275)	$	(1,337)

The movements related to pension and OPEB in AOCI for Empire Electric System, Empire Gas Systems, St. Lawrence Gas System and Liberty NY Water System are reclassified to regulatory accounts since it is probable the unfunded amount of these plans will be afforded rate recovery (note 7(f)).

Notes to the Consolidated Financial Statements 111

Algonquin Power & Utilities Corp.

Notes to the Consolidated Financial Statements

December 31, 2023 and 2022

(in thousands of U.S. dollars, except as noted and per share amounts)

10.Pension and other post-employment benefits (continued)

(c)Assumptions

Weighted average assumptions used to determine net benefit obligation for 2023 and 2022 were as follows: 

	Pension benefits				OPEB
	2023		2022		2023		2022
Discount rate	5.19	%	5.48	%	5.22	%	5.49	%
Interest crediting rate (for cash balance plans)	4.48	%	4.50	%	N/A		N/A
Rate of compensation increase	3.60	%	3.70	%	N/A		N/A
Health care cost trend rate
Before age 65					7.00	%	6.00	%
Age 65 and after					6.00	%	6.00	%
Assumed ultimate medical inflation rate					4.50	%	4.75	%
Year in which ultimate rate is reached					2034		2033

The mortality assumption for December 31, 2023 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, 2023 uses the 2014 Canadian Pensioners' Mortality Table combined with mortality improvement scale CPM-B.

In selecting an assumed discount rate, the Company uses a modelling process that involves selecting a portfolio of high-quality corporate debt issuances (AA or better) whose cash flows (via coupons or maturities) match the timing and amount of the Company’s expected future benefit payments. The Company considers the results of this modelling process, as well as overall rates of return on high-quality corporate bonds and changes in such rates over time, to determine its assumed discount rate.

The rate of return assumptions are based on projected long-term market returns for the various asset classes in which the plans are invested, weighted by the target asset allocations.

Weighted average assumptions used to determine net benefit cost for 2023 and 2022 were as follows: 

	Pension benefits				OPEB
	2023		2022		2023		2022
Discount rate	5.35	%	2.94	%	5.49	%	3.00	%
Expected return on assets	6.38	%	6.19	%	6.45	%	6.48	%
Rate of compensation increase	3.99	%	3.91	%	n/a		n/a
Health care cost trend rate
Before Age 65					6.00	%	5.88	%
Age 65 and after					6.00	%	5.88	%
Assumed ultimate medical inflation rate					4.75	%	4.75	%
Year in which ultimate rate is reached					2033		2031

Notes to the Consolidated Financial Statements 112

Algonquin Power & Utilities Corp.

Notes to the Consolidated Financial Statements

December 31, 2023 and 2022

(in thousands of U.S. dollars, except as noted and per share amounts)

10.Pension and other post-employment benefits (continued)

(d)Benefit costs

The following table lists the components of net benefit cost for the pension and OPEB plans. Service cost is recorded as part of operating expenses and non-service costs are recorded as part of Pension and other post-employment non-service costs in the consolidated statements of operations. The employee benefit costs related to businesses acquired are recorded in the consolidated statements of operations from the date of acquisition.

	Pension benefits				OPEB
	2023		2022		2023		2022
Service cost	$	11,954	$	16,309	$	3,253	$	6,277
Non-service costs
Interest cost	33,687		24,787		11,510		9,146
Expected return on plan assets	(31,990)		(41,226)		(9,736)		(11,359)
Amortization of net actuarial loss	(852)		3,452		(3,559)		(56)
Amortization of prior service credits	(1,491)		(1,584)		(853)		24
Amortization due to plan settlements	—		(15)		—		—
Amortization of regulatory accounts	16,258		22,952		6,965		4,829
	$	15,612	$	8,366	$	4,327	$	2,584
Net benefit cost	$	27,566	$	24,675	$	7,580	$	8,861

(e)Plan assets

The Company’s investment strategy for its pension and post-employment plan assets is to maintain a diversified portfolio of assets with the primary goal of meeting long-term cash requirements as they become due.

The Company’s target asset allocation is as follows:

Asset class	Target (%)		Range (%)
Equity securities	41.6	%	30% - 100%
Debt securities	48.6	%	20% - 60%
Other	9.8	%	0% - 20%
	100	%

The fair values of investments as of December 31, 2023, by asset category, are as follows:

Asset class	2023		Percentage
Equity securities	$	376,158	47	%
Debt securities	377,272		47	%
Other	51,180		6	%
	$	804,610	100	%

As of December 31, 2023, the plan assets do not include any material investments in AQN. 

Notes to the Consolidated Financial Statements 113

Algonquin Power & Utilities Corp.

Notes to the Consolidated Financial Statements

December 31, 2023 and 2022

(in thousands of U.S. dollars, except as noted and per share amounts)

10.Pension and other post-employment benefits (continued)

(e)Plan assets (continued)

All investments as of December 31, 2023 are valued using Level 1 inputs except for $26,381 of institutional private equity investments using Level 3 fair value measurement. These private equity funds invest in the private equity secondary market and in the credit markets. These funds are not traded in the open market, and are valued based on the underlying securities within the funds. The underlying securities are valued at fair value by the fund managers by using securities exchange quotations, pricing services, obtaining broker-dealer quotations, reflecting valuations provided in the most recent financial reports, or at a good faith estimate using fair market value principles.

The following table summarizes the changes fair value of these Level 3 assets as of December 31:

	Level 3
Balance, January 1, 2023	$	21,904
Contributions into funds	4,603
Return on assets	2,205
Distributions	(2,331)
Balance, December 31, 2023	$	26,381

(f)Cash flows

The Company expects to contribute $23,248 to its pension plans and $3,583 to its post-employment benefit plans in 2024.

The expected benefit payments over the next ten years are as follows: 

	2024		2025		2026		2027		2028		2029-2033
Pension plan	$	48,271	$	49,652	$	49,389	$	50,443	$	50,751	$	255,465
OPEB	$	11,718	$	12,303	$	12,623	$	13,105	$	13,487	$	71,230

11.Other assets

Other assets consist of the following:

	2023		2022
Restricted cash	$	19,997	$	43,562
Pension and OPEB plan assets (note 10(a))	48,477		26,482
Long-term deposits and cash collateral	19,336		22,537
Income taxes recoverable	9,988		7,100
Deferred financing costs (a)	27,176		28,586
Insurance recoveries (note 22(a))	66,000		—
Other (b)	31,080		21,596
	$	222,054	$	149,863
Less: current portion	(23,061)		(22,564)
	$	198,993	$	127,299

(a)Deferred financing costs

Deferred financing costs represent costs of arranging the Company’s revolving credit facilities and intercompany loans as well as the portion of transactions costs related to the Green Equity Units that will be recorded against the common shares when issued.

Notes to the Consolidated Financial Statements 114

Algonquin Power & Utilities Corp.

Notes to the Consolidated Financial Statements

December 31, 2023 and 2022

(in thousands of U.S. dollars, except as noted and per share amounts)

11.Other assets (continued)

(b)Other

Other includes various deferred charges that are expected to be transferred to utility plant upon reaching certain milestones as well as prepaid long-term service contracts.

12.Other long-term liabilities

Other long-term liabilities consist of the following: 

	2023		2022
Contract adjustment payments (a)	$	39,590	$	113,876
Asset retirement obligations (b)	115,611		116,584
Advances in aid of construction (c)	88,135		88,546
Environmental remediation obligation (d)	40,772		42,457
Customer deposits (e)	36,294		34,675
Unamortized investment tax credits (f)	17,255		17,649
Deferred credits and contingent consideration (g)	40,945		39,498
Preferred shares, Series C (h)	—		12,072
Hook-up fees (i)	7,425		32,463
Lease liabilities	20,493		21,834
Contingent development support obligations (j)	12,666		8,824
Note payable to related party (k)	25,808		25,808
Contingent liability (note 22(a))	66,000		—
Other	35,338		41,156
	$	546,332	$	595,442
Less: current portion	(80,458)		(134,212)
	$	465,874	$	461,230

(a)Contract adjustment payment

In June 2021, the Company sold 23,000,000 Green Equity Units for total gross proceeds of $1,150,000. Total annual distributions on the Green Equity Units are at a rate of 7.75%, consisting of interest on the notes (1.18% per year) and payments under the share purchase contract (6.57% per year). The present value of the contract adjustment payments was estimated at $222,378 and recorded in other liabilities. The contract adjustment payments amount is accreted over the three-year period.

(b)Asset retirement obligations

    Asset retirement obligations mainly relate to legal requirements to: (i) remove wind farm facilities upon termination of land leases; (ii) cut (disconnect from the distribution system), purge (cleanup of natural gas and polychlorinated biphenyls (“PCB”) contaminants) and cap natural gas mains within the natural gas distribution and transmission system when mains are retired in place, or sections of natural gas main are removed from the pipeline system; (iii) clean and remove storage tanks containing waste oil and other waste contaminants; (iv) remove certain river water intake structures and equipment; (v) dispose of coal combustion residuals and PCB contaminants; (vi) remove asbestos upon major renovation or demolition of structures and facilities; and (vii) decommission and restore power generation engines and related facilities.

Notes to the Consolidated Financial Statements 115

Algonquin Power & Utilities Corp.

Notes to the Consolidated Financial Statements

December 31, 2023 and 2022

(in thousands of U.S. dollars, except as noted and per share amounts)

12.Other long-term liabilities (continued)

(b)Asset retirement obligations (continued)

Changes in the asset retirement obligations are as follows:

	2023		2022
Opening balance	$	116,584	$	142,147
Obligation assumed	1,077		793
Retirement activities	(6,902)		(27,980)
Accretion	4,440		4,589
Change in cash flow estimates	412		(2,965)
Closing balance	$	115,611	$	116,584

As the cost of retirement of utility assets in the United States is expected to be recovered through rates, a corresponding regulatory asset is recorded for liability accretion and asset depreciation expense (note 7(j)).

(c)Advances in aid of construction

The Company’s regulated utilities have various agreements with real estate development companies (the “developers”) conducting business within the Company’s utility service territories, whereby funds are advanced to the Company by the developers to assist with funding some or all of the costs of the development.

In many instances, developer advances can be subject to refund, but the refund is non-interest bearing. Refunds of developer advances are made over periods generally ranging from 5 to 40 years. Advances not refunded within the prescribed period are usually not required to be repaid. After the prescribed period has lapsed, any remaining unpaid balance is transferred to contributions in aid of construction and recorded as an offsetting amount to the cost of property, plant and equipment. In 2023, $238 (2022 - $1,299) was transferred from advances in aid of construction to contributions in aid of construction.

(d)Environmental remediation obligation

A number of the Company’s regulated utilities were named as potentially responsible parties for remediation of several sites at which hazardous waste is alleged to have been disposed as a result of historical operations of manufactured natural gas plants (“MGP”) and related facilities. The Company is currently investigating and remediating, as necessary, those MGP and related sites in accordance with plans submitted to the agency with authority for each of the respective sites.

The Company estimates the remaining undiscounted, unescalated cost of the environmental cleanup activities will be $46,187 (2022 - $48,346), which at discount rates ranging from 3.4% to 4.3% represents the recorded accrual of $40,772 as of December 31, 2023 (2022 - $42,457). Approximately $25,713 is expected to be incurred over the next three years, with the balance of cash flows to be incurred over the following 27 years.

Changes in the environmental remediation obligation are as follows:

	2023		2022
Opening balance	$	42,457	$	55,224
Remediation activities	(3,687)		(5,243)
Accretion	1,616		2,167
Changes in cash flow estimates	1,395		1,344
Revision in assumptions	(1,009)		(11,035)
Closing balance	$	40,772	$	42,457

The Regulators for the New England Gas System and Energy North Gas System provide for the recovery of actual expenditures for site investigation and remediation over a period of seven years and, accordingly, as of December 31, 2023, the Company has reflected a regulatory asset of $66,779 (2022 - $70,529) for the MGP and related sites (note 7(g)).

Notes to the Consolidated Financial Statements 116

Algonquin Power & Utilities Corp.

Notes to the Consolidated Financial Statements

December 31, 2023 and 2022

(in thousands of U.S. dollars, except as noted and per share amounts)

12.Other long-term liabilities (continued)

(e)Customer deposits

Customer deposits result from the Company’s obligation by Regulators to collect a deposit from customers of its facilities under certain circumstances when services are connected. The deposits are refundable as allowed under the facilities’ regulatory agreement.

(f)Unamortized investment tax credits

The unamortized investment tax credits were assumed in connection with the acquisition of the Empire Electric System. The investment tax credits are associated with an investment made in a generating station. The credits are being amortized over the life of the generating station.

(g)Deferred credits and contingent consideration

Deferred credits and contingent consideration include unresolved contingent consideration related to prior acquisitions which is expected to be paid.

(h)Preferred shares, Series C

During the year ended December 31, 2023, 100 Series C preferred shares of AQN that had previously been issued in exchange for 100 Class B limited partnership units of St. Leon Wind Energy LP, were redeemed for $14,515, and a loss on settlement of $2,377 was recorded in other net losses (note 19(f)) in the consolidated statements of operations. As a result of the redemption, no Series C preferred shares of AQN remain outstanding.

(i)Hook-up fees

Hook-up fees result from the collection from customers of funds for installation and connection to the utility’s infrastructure. The fees are refundable as allowed under the facilities’ regulatory agreement.

(j)Contingent development support obligations

The Company provides credit support necessary for the continued development and construction of its equity investees’ wind and solar power electric development projects and infrastructure development projects. The contingent development support obligations represent the fair value of the support provided (note 8(c)).

(k)Note payable to related party

In 2021, a subsidiary of the Company made a tax equity investment into New Market Solar Investco, LLC, an equity investee of the Company and indirect owner of the New Market Solar Project. Following the closing of the construction financing facility for the New Market Solar Project, certain excess funds were distributed to the Company and in return the Company issued a promissory note of $25,808 payable to New Market Solar Investco, LLC. The promissory note bears an interest rate of 4% annually and has a maturity date of December 16, 2031.

13.Shareholders’ capital

(a)Common shares

Number of common shares 

	2023	2022
Common shares, beginning of year	683,614,803	671,960,276
Public offering	—	2,861,709
Dividend reinvestment plan	4,370,289	7,676,666
Exercise of share-based awards (c)	1,284,532	1,115,398
Conversion of convertible debentures	1,415	754
Common shares, end of year	689,271,039	683,614,803

Notes to the Consolidated Financial Statements 117

Algonquin Power & Utilities Corp.

Notes to the Consolidated Financial Statements

December 31, 2023 and 2022

(in thousands of U.S. dollars, except as noted and per share amounts)

13.Shareholders’ capital (continued)

(a)    Common shares (continued)

Authorized

AQN is authorized to issue an unlimited number of common shares. The holders of the common shares are entitled to dividends if, as and when declared by the board of directors of AQN (the “Board”); to one vote per share at meetings of the holders of common shares; and upon liquidation, dissolution or winding up of AQN to receive pro rata the remaining property and assets of AQN, subject to the rights of any shares having priority over the common shares.

The Company has a shareholders’ rights plan (the “Rights Plan”), which expires in 2025. Under the Rights Plan, one right is issued with each issued share of the Company. The rights remain attached to the shares and are not exercisable or separable unless one or more certain specified events occur. If a person or group acting in concert acquires 20 percent or more of the outstanding shares (subject to certain exceptions) of the Company, the rights will entitle the holders thereof (other than the acquiring person or group) to purchase shares at a 50 percent discount from the then-current market price. The rights provided under the Rights Plan are not triggered by any person making a “Permitted Bid”, as defined in the Rights Plan.

(i)At-the-market equity program

On August 15, 2022, AQN re-established its at-the-market equity program (“ATM Program”) that allowed the Company to issue up to $500,000 (or the equivalent in Canadian dollars) of common shares from treasury to the public from time to time, at the Company’s discretion, at the prevailing market price when issued on the Toronto Stock Exchange (“TSX”), the New York Stock Exchange (“NYSE”) or any other existing trading market for the common shares of the Company in Canada or the United States.

During the year ended December 31, 2023, the Company did not issue any common shares under its ATM Program. The ATM Program terminated in accordance with its terms on December 19, 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 $551,086 ($544,295 net of commissions). Other related costs, primarily related to the establishment and subsequent re-establishments of the ATM program, were $4,843.

(ii)Dividend reinvestment plan

The Company has a common shareholder dividend reinvestment plan, which, when the plan is active, provides an opportunity for holders of AQN’s common shares who reside in Canada, the United States, or, subject to AQN’s consent, other jurisdictions, to reinvest the cash dividends paid on their common shares in additional common shares which, at AQN’s election, are either purchased on the open market or newly issued from treasury. Effective March 3, 2022, common shares purchased under the plan were issued at a 3% discount (previously at 5%) to the prevailing market price (as determined in accordance with the terms of the plan). Effective March 16, 2023, AQN suspended the dividend reinvestment plan. Effective for the first quarter 2023 dividend (paid on April 14, 2023 to shareholders of record on March 31, 2023), shareholders participating in the dividend reinvestment plan began receiving cash dividends. If the Company elects to reinstate the dividend reinvestment plan in the future, shareholders who were enrolled in the dividend reinvestment plan at its suspension and remain enrolled at reinstatement will automatically resume participation in the dividend reinvestment plan.

(b)Preferred shares

AQN is authorized to issue an unlimited number of preferred shares, issuable in one or more series, containing terms and conditions as approved by the Board.

Notes to the Consolidated Financial Statements 118

Algonquin Power & Utilities Corp.

Notes to the Consolidated Financial Statements

December 31, 2023 and 2022

(in thousands of U.S. dollars, except as noted and per share amounts)

13.Shareholders’ capital (continued)

The Company has the following Cumulative Rate Reset Preferred Shares, Series A (the “Series A Shares”) and Cumulative Rate Reset Preferred Shares, Series D (the “Series D Shares”) issued and outstanding as of December 31, 2023 and 2022:

	Number of shares	Price per share	Carrying amount C$		Carrying amount $
Series A Shares	4,800,000	C$25.00	C$	116,546	$	100,463
Series D Shares	4,000,000	C$25.00	C$	97,259	$	83,836
					$	184,299

The holders of Series A Shares are entitled to receive quarterly fixed cumulative preferential cash dividends, if, as and when declared by the Board. The dividend for each year up to, but excluding, December 31, 2023 was an annual amount of C$1.2905 per share. The dividend rate for the five-year period from, and including December 31, 2023 but excluding December 31, 2028 will be an annual amount of C$1.6440per share. The Series A Shares dividend rate will reset on December 31, 2028 and every five years thereafter at a rate equal to the then five-year Government of Canada bond yield plus 2.94%. The Series A Shares were redeemable at C$25 per share at the option of the Company on December 31, 2023 and are redeemable every fifth year thereafter. The holders of Series A Shares have the right to convert their shares into cumulative floating rate preferred shares, Series B, subject to certain conditions, on December 31, 2028 (or the next business day, if such day is not a business day), and every fifth year thereafter.

The holders of Series D Shares are entitled to receive fixed cumulative preferential dividends as and when declared by the Board at an annual amount of C$1.2728 per share for each year up to, but excluding, March 31, 2024. The Series D Share dividend will reset on March 31, 2024 and every five years thereafter at a rate equal to the then five-year Government of Canada bond plus 3.28%. The Series D Shares are redeemable at C$25 per share at the option of the Company on March 31, 2024 (or the next business day, if such day is not a business day) and every fifth year thereafter. Accordingly, the Series D Shares are redeemable by the Company on April 1, 2024, but the Company has elected not to exercise its redemption right. The holders of Series D Shares have the right to convert their shares into cumulative floating rate preferred shares, Series E, subject to certain conditions, on March 31, 2024 (or the next business day, if such day is not a business day), and every fifth year thereafter.

(c)Share-based compensation

For the year ended December 31, 2023, AQN recorded $11,293 (2022 - $10,920) in total share-based compensation expense as follows: 

	2023		2022
Share options	$	1,325	$	980
Director deferred share units	949		960
Employee share purchase	897		562
Performance and restricted share units	8,122		8,418
Total share-based compensation	$	11,293	$	10,920

The compensation expense is recorded within operating expenses in the consolidated statements of operations. The portion of share-based compensation costs capitalized as cost of construction is insignificant.

As of December 31, 2023, total unrecognized compensation costs related to non-vested share-based awards are $23,883 and are expected to be recognized over a period of 1.8 years.

(i)Share option plan

The Company’s share option plan (the “Plan”) permits the grant of share options to officers, directors, employees and selected service providers. The aggregate number of shares that may be reserved for issuance under the Plan must not exceed 8% of the number of shares outstanding at the time the options are granted.

Notes to the Consolidated Financial Statements 119

Algonquin Power & Utilities Corp.

Notes to the Consolidated Financial Statements

December 31, 2023 and 2022

(in thousands of U.S. dollars, except as noted and per share amounts)

13.Shareholders’ capital (continued)

(c)Share-based compensation (continued)

(i)Share option plan (continued)

The number of shares subject to each option, the option price, the expiration date, the vesting and other terms and conditions relating to each option shall be determined by the Board (or the compensation committee of the Board (“Compensation Committee”)) from time to time. Dividends on the underlying shares do not accumulate during the vesting period. Option holders may elect to surrender any portion of the vested options that is then exercisable in exchange for the “In-the-Money Amount”. In accordance with the Plan, the “In-The-Money Amount” represents the excess, if any, of the market price of a share at such time over the option price, in each case such “In-the-Money Amount” being payable by the Company in cash or common shares at the election of the Company. As the Company does not expect to settle these instruments in cash, these options are accounted for as equity awards.

The Compensation Committee may accelerate the vesting of the unvested options then held by the optionee at the Compensation Committee's discretion. In the event that the Company restates its financial results, any unpaid or unexercised options may be cancelled at the discretion of the Compensation Committee in accordance with the terms of the Company’s clawback policy.

The estimated fair value of options, including the effect of estimated forfeitures, is recognized as expense on a straight-line basis over the options’ vesting periods while ensuring that the cumulative amount of compensation cost recognized at least equals the value of the vested portion of the award at that date. The Company determines the fair value of options granted using the Black-Scholes option-pricing model. The risk-free interest rate is based on the zero-coupon Canada Government bond with a similar term to the expected life of the options at the grant date. Expected volatility was estimated based on the historical volatility of the Company’s common shares.  The expected life was based on experience to date. The dividend yield rate was based upon recent historical dividends paid on AQN common shares.

The following assumptions were used in determining the fair value of share options granted: 

	2023			2022
Risk-free interest rate	3.4		%	1.9		%
Expected volatility	27		%	23		%
Expected dividend yield	8.6		%	4.3		%
Expected life	5.50 years			5.50 years
Weighted average grant date fair value per option	$	1.04		$	2.44

Share option activity during the years is as follows: 

	Number of awards	Weighted average exercise price		Weighted average remaining contractual term (years)	Aggregate intrinsic value
Balance, January 1, 2022	2,040,528	C$	15.45	6.11	C$	3,145
Granted	646,090	19.11		7.22	—
Exercised	(40,074)	13.92		5.95	103
Forfeited	(19,764)	19.11		—	—
Balance, December 31, 2022	2,626,780	C$	16.02	5.63	C$	—
Granted	1,368,744	10.76		7.24	—
Exercised	—	—		—	—
Forfeited	(1,327,799)	16.55		—	—
Balance, December 31, 2023	2,667,725	C$	14.71	5.18	C$	—
Exercisable, December 31, 2023	2,621,420	C$	17.11	4.50	C$	—

Notes to the Consolidated Financial Statements 120

Algonquin Power & Utilities Corp.

Notes to the Consolidated Financial Statements

December 31, 2023 and 2022

(in thousands of U.S. dollars, except as noted and per share amounts)

13.Shareholders’ capital (continued)

(c)Share-based compensation (continued)

(ii)Employee share purchase plan

Under the Company’s ESPP, eligible employees may have a portion of their earnings withheld to be used to purchase the Company’s common shares. The Company will match 20% of the employee contribution amount for the first five thousand dollars per employee contributed annually and 10% of the employee contribution amount for contributions over five thousand dollars up to ten thousand dollars annually. Common shares purchased through the Company match portion shall not be eligible for sale by the participant for a period of one year following the purchase date on which such shares were acquired. At the Company’s option, the common shares may be (i) issued to participants from treasury at the average share price or (ii) acquired on behalf of participants by purchases through the facilities of the TSX or NYSE by an independent broker. The aggregate number of common shares reserved for issuance from treasury by AQN under the ESPP shall not exceed 4,000,000 common shares.

The Company uses the fair value based method to measure the compensation expense related to the Company’s contribution. For the year ended December 31, 2023, a total of 752,582 common shares (2022 - 414,338) were issued to employees under the ESPP.

(iii)Director’s deferred share units

Under the Company’s DSU plan, non-employee directors of the Company may elect annually to receive all or any portion of their compensation in DSUs in lieu of cash compensation. Directors’ fees are paid on a quarterly basis and at the time of each payment of fees, the applicable amount is converted to DSUs. A DSU has a value equal to one of the Company’s common shares. Dividends accumulate in the DSU account and are converted to DSUs based on the market value of the shares on that date. DSUs cannot be redeemed until the director retires, resigns, or otherwise leaves the Board. The DSUs provide for settlement in cash or common shares at the election of the Company. As the Company does not expect to settle these instruments in cash, these options are accounted for as equity awards. For the year ended December 31, 2023, a total of 181,328 DSUs (2022 - 120,513) were issued and 102,460 DSUs (2022 - 5,176) were settled in exchange for 50,677 common shares issued from treasury, and 51,783 DSUs were settled at their cash value as payment for tax withholding related to the settlement of the awards. As of December 31, 2023, 724,583 (2022 - 645,714) DSUs are outstanding pursuant to the election of the directors to defer a percentage of their director’s fee in the form of DSUs. The aggregate number of common shares reserved for issuance from treasury by AQN under the DSU plan shall not exceed 1,000,000 common shares.

(iv)Performance and restricted share units

The Company offers a PSU and RSU plan to its employees as part of the Company’s long-term incentive program. PSUs have been granted annually for three-year overlapping performance cycles. The PSUs vest at the end of the three-year cycle and are calculated based on established performance criteria. At the end of the three-year performance periods, the number of common shares issued can range from 2.5% to 237% of the number of PSUs granted. RSU vesting conditions and dates vary by grant and are outlined in each award letter. RSUs are not subject to performance criteria. Dividends accumulating during the vesting period are converted to PSUs and RSUs based on the market value of the shares on that date and are recorded in equity as the dividends are declared. None of the PSUs or RSUs have voting rights. Any PSUs or RSUs not vested at the end of a performance period will expire. The PSUs and RSUs provide for settlement in cash or common shares at the election of the Company. As the Company does not expect to settle these instruments in cash, these units are accounted for as equity awards. The aggregate number of common shares reserved for issuance from treasury by AQN under the PSU and RSU plan shall not exceed 7,000,000 common shares.

Compensation expense associated with PSUs is recognized ratably over the performance period. Achievement of the performance criteria is estimated as at the consolidated balance sheet dates. Compensation cost recognized is adjusted to reflect the performance conditions estimated to date.

Notes to the Consolidated Financial Statements 121

Algonquin Power & Utilities Corp.

Notes to the Consolidated Financial Statements

December 31, 2023 and 2022

(in thousands of U.S. dollars, except as noted and per share amounts)

13.Shareholders’ capital (continued)

(c)Share-based compensation (continued)

(iv)Performance and restricted share units (continued)

A summary of the PSUs and RSUs follows: 

	Number of awards	Weighted average grant-date fair value		Weighted average remaining contractual term (years)	Aggregate intrinsic value
Balance, January 1, 2022	2,443,672	C$	18.07	1.72	C$	44,646
Granted, including dividends	1,090,457	17.99		2.00	17,524
Exercised	(1,221,620)	12.62		—	23,636
Forfeited	(202,799)	18.94		—	418
Balance, December 31, 2022	2,109,710	C$	18.38	1.76	C$	18,608
Granted, including dividends	2,841,967	10.98		2.02	25,329
Exercised	(922,883)	18.73		—	10,125
Forfeited	(451,047)	15.07		—	3,771
Balance, December 31, 2023	3,577,747	C$	18.38	1.76	C$	29,910
Exercisable, December 31, 2023	597,363	C$	19.98	0.22	C$	4,994

(v)Bonus deferral RSUs

Eligible employees have the option to receive a portion or all of their annual bonus payment in RSUs in lieu of cash. These RSUs provide for settlement in shares, and therefore these RSUs are accounted for as equity awards. The RSUs granted are 100% vested and, therefore, compensation expense associated with these RSUs is recognized immediately upon issuance.

During the year ended December, 31, 2023, 77,981 (2022 - 55,445) bonus deferral RSUs were granted to employees of the Company. In addition, the Company settled 69,115 (2022 - 178,368) bonus deferral RSUs in exchange for 31,455 (2022 - 82,886) common shares issued from treasury, and 37,660 (2022- 95,482) RSUs were settled at their cash value as payment for tax withholdings related to the settlement of the RSUs. As of December 31, 2023, 167,352 (2022 - 158,486) bonus deferral RSUs are outstanding.

Notes to the Consolidated Financial Statements 122

Algonquin Power & Utilities Corp.

Notes to the Consolidated Financial Statements

December 31, 2023 and 2022

(in thousands of U.S. dollars, except as noted and per share amounts)

14.Accumulated other comprehensive income (loss)

    AOCI consists of the following balances, net of tax:

	Foreign currency cumulative translation		Unrealized gain on cash flow hedges		Pension and post-employment actuarial changes		Total
Balance, January 1, 2022	$	(76,615)	$	(3,514)	$	8,452	$	(71,677)
Other comprehensive income (loss)	(18,013)		(128,838)		23,722		(123,129)
Amounts reclassified from AOCI to the consolidated statement of operations	(5,489)		34,543		4,039		33,093
Net current period OCI	$	(23,502)	$	(94,295)	$	27,761	$	(90,036)
OCI attributable to the non-controlling interests	1,650		—		—		1,650
Net current period OCI attributable to shareholders of AQN	$	(21,852)	$	(94,295)	$	27,761	$	(88,386)
Balance, December 31, 2022	$	(98,467)	$	(97,809)	$	36,213	$	(160,063)
Other comprehensive income (loss)	(3,788)		57,351		8,395		61,958
Amounts reclassified from AOCI to the consolidated statement of operations	(1,598)		2,136		(3,702)		(3,164)
Net current period OCI	$	(5,386)	$	59,487	$	4,693	$	58,794
OCI attributable to the non-controlling interests	(1,017)		—		—		(1,017)
Net current period OCI attributable to shareholders of AQN	$	(6,403)	$	59,487	$	4,693	$	57,777
Balance, December 31, 2023	$	(104,870)	$	(38,322)	$	40,906	$	(102,286)

Amounts reclassified from AOCI for foreign currency cumulative translation affected interest expense and derivative gain (loss); those for unrealized gain (loss) on cash flow hedges affected revenue from non-regulated energy sales, interest expense and derivative gain (loss) while those for pension and post-employment actuarial changes affected pension and post-employment non-service costs.

15.Dividends

All dividends of the Company are made on a discretionary basis as determined by the Board. The Company declares and pays the dividends on its common shares in U.S. dollars. Dividends declared were as follows:

	2023				2022
	Dividend		Dividend per share		Dividend		Dividend per share
Common shares	$	301,771	$	0.4340	$	486,043	$	0.7130
Series A Shares	C$	6,194	C$	1.2905	C$	6,194	C$	1.2905
Series D Shares	C$	5,091	C$	1.2728	C$	5,091	C$	1.2728

Notes to the Consolidated Financial Statements 123

Algonquin Power & Utilities Corp.

Notes to the Consolidated Financial Statements

December 31, 2023 and 2022

(in thousands of U.S. dollars, except as noted and per share amounts)

16.Related party transactions

(a)Equity-method investments

The Company provides administrative and development services to its equity-method investees and is reimbursed for incurred costs. To that effect, during 2023, the Company charged its equity-method investees $34,733 (2022 - $38,215) for administrative services and $37,802 (2022 - $25,645) for development services. Additionally, Liberty Development JV Inc. (note 8(c)), an equity-method investee of the Company that is the Company’s joint venture with funds managed by the Infrastructure and Power strategy of Ares Management, LLC for its non-regulated development platform, provides development services to the Company on specified projects, for which it earns a development fee upon reaching certain milestones. During the year, the development fees charged to the Company were $27,933 (2022 - $12,628).

Subsequent to year-end, on January 4, 2024, the Company purchased Ares’ 50% interest in Liberty Development JV Inc. and Liberty Development Energy Solutions B.V.

Investments in and acquisitions of equity-method investments are described in note 8(c).

(b)Non-controlling interest and redeemable non-controlling interest held by related party

Non-controlling interest and redeemable non-controlling interest held by related party are described in note 17(c).

(c)     Transactions with Atlantica

On December 28, 2023, Liberty Development Spain, S.A., a wholly owned subsidiary of the Company entered into an agreement to sell its 100% equity interests in Liberty Jimena, S.L. and Liberty Caparacena, S.L., and its 80% equity interest in Liberty Infrastructuras, S.L. to Atlantica for a nominal amount. As a result, the Company recorded an impairment loss of $1,481, included in asset impairment charge in the consolidated statements of operations. The transaction closed on January 23, 2024.

The above related party transactions have been recorded at the exchange amounts agreed to by the parties to the transactions.

17.Non-controlling interests and redeemable non-controlling interests

Net effect attributable to non-controlling interests for the years ended December 31 consists of the following:

	2023		2022
HLBV and other adjustments attributable to:
Non-controlling interests - tax equity partnership units	$	114,141	$	108,695
Non-controlling interests - redeemable tax equity partnership units	1,324		6,298
Other net earnings attributable to:
Non-controlling interests	(27,564)		(3,670)
	$	87,901	$	111,323
Redeemable non-controlling interest, held by related party	(25,922)		(15,157)
Net effect of non-controlling interests	$	61,979	$	96,166

The non-controlling tax equity investors (“tax equity partnership units”) in the Company's U.S. wind power and solar power-generating facilities are entitled to allocations of earnings, tax attributes and cash flows in accordance with contractual agreements. The share of earnings (loss) attributable to the non-controlling interest holders in these subsidiaries is calculated using the HLBV method of accounting as described in note 1(s).

Notes to the Consolidated Financial Statements 124

Algonquin Power & Utilities Corp.

Notes to the Consolidated Financial Statements

December 31, 2023 and 2022

(in thousands of U.S. dollars, except as noted and per share amounts)

17.Non-controlling interests and redeemable non-controlling interests (continued)

Non-controlling interests

	Non-controlling interests - tax equity partnership units (a)				Other non-controlling interests (b)				Non-controlling interests held by related parties (c)
	2023		2022		2023		2022		2023		2022
Opening balance	$	1,225,608	$	1,377,117	$	333,362	$	64,807	$	57,822	$	81,158
Net earnings (loss) attributable to NCI	(114,141)		(108,695)		27,564		3,670		—		—
Contributions received, net	107,933		6,182		—		267,515		—		—
Dividends and distributions declared	(22,743)		(36,736)		(14,497)		(3,350)		(17,082)		(20,978)
Repurchase of non-controlling interest	—		(12,249)		—		—		—		—
OCI	63		(11)		909		720		45		(2,358)
Closing balance	$	1,196,720	$	1,225,608	$	347,338	$	333,362	$	40,785	$	57,822

(a)     Non-controlling interests - tax equity partnership units

The Company obtained control of the Deerfield II Wind Facility during the year (note 3). Post-acquisition, third-party tax equity investors funded $98,955 in exchange for Class A partnership units in the entity. In addition, the Company received $9,084 (2022 - $6,182) of production based cash contributions during the year relating to other projects.

(b)     Other non-controlling interests

On December 29, 2022, the Company sold a 49% non-controlling interest in three operating wind facilities in the United States totalling 551 MW of installed capacity: the Odell Wind Facility in Minnesota, the Deerfield Wind Facility in Michigan and the Sugar Creek Wind Facility in Illinois. The consideration of $277,500 was recorded as an increase to non-controlling interest, except for a portion of $5,000, which is subject to refund if some conditions are met and as such was recorded as redeemable non-controlling interest.

(c)     Non-controlling interest held by related parties

In November 2021, Liberty Development JV Inc. invested $39,376 in Algonquin (AY Holdco) B.V., a consolidated subsidiary of the Company. In May 2019, AYES Canada acquired an interest in a consolidated subsidiary of the Company for $96,752 (C$130,103) (note 8(b)). The investment by AYES Canada and Liberty Development JV Inc. are presented as a non-controlling interest held by related parties.

Notes to the Consolidated Financial Statements 125

Algonquin Power & Utilities Corp.

Notes to the Consolidated Financial Statements

December 31, 2023 and 2022

(in thousands of U.S. dollars, except as noted and per share amounts)

17.Non-controlling interests and redeemable non-controlling interests (continued)

Redeemable non-controlling interests

Non-controlling interests in subsidiaries that are redeemable upon the occurrence of uncertain events not solely within AQN’s control are classified as temporary equity on the consolidated balance sheets. If the redemption is probable or currently redeemable, the Company records the instruments at their redemption value. Redemption is not considered probable as of December 31, 2023.

Liberty Global Energy Solutions (note 8(c)), an equity investee of the Company, has a secured credit facility in the amount of $306,500 with a previous maturity date of January 26, 2024. Subsequent to year-end, on January 8, 2024, the secured credit facility was renewed with a maturity date of September 30, 2024. It is collateralized through a pledge of Atlantica ordinary shares held by AY Holdings. A collateral shortfall would occur if the net obligation (as defined in the credit agreement) would equal or exceed 50% of the market value of such Atlantica shares, in which case the lenders would have the right to sell Atlantica shares to eliminate the collateral shortfall. The Liberty Global Energy Solutions secured credit facility is repayable on demand if Atlantica ceases to be a public company or if certain other events are announced or completed that could restrict AY Holdings’ ability to sell or transfer its Atlantica ordinary shares. Liberty Global Energy Solutions has a preference share ownership in AY Holdings which AQN reflects as redeemable non-controlling interest held by related party.

As a result of the subsequent event described in note 8(c), the redeemable non-controlling interest held by related party will be reclassified to long-term debt in 2024.

Changes in redeemable non-controlling interests are as follows:

	Redeemable non-controlling interests held by related party				Redeemable non-controlling interests
	2023		2022		2023		2022
Opening balance	$	307,856	$	306,537	$	11,520	$	12,989
Net earnings (loss) attributable to NCI	25,922		15,157		(1,324)		(6,298)
Contributions, net of costs	—		—		—		5,000
Dividends and distributions declared	(25,428)		(13,838)		(183)		(171)
Closing balance	$	308,350	$	307,856	$	10,013	$	11,520

18.Income taxes

The provision for income taxes in the consolidated statements of operations represents an effective tax rate different than the Canadian enacted statutory rate of 26.5% (2022 - 26.5%). The differences are as follows:

	2023		2022
Expected income tax recovery at Canadian statutory rate	$	(31,696)	$	(97,962)
Increase (decrease) resulting from:
Effect of differences in tax rates on transactions in and within foreign jurisdictions and change in tax rates	(46,628)		(55,315)
Adjustments from investments carried at fair value	16,128		51,314
Non-controlling interests share of income	24,677		30,025
Change in valuation allowance	10,786		41,702
Acquisition related state deferred tax adjustments	—		5,998
Capital gain rate differential on disposal of renewable assets	—		(7,340)
Tax credits	(54,788)		(18,440)
Amortization and settlement of excess deferred income tax	(12,785)		(14,855)
Deferred income taxes on regulated income recorded as regulatory assets	(878)		(1,986)
Other permanent differences	5,341		4,591
Other	3,543		755
Income tax recovery	$	(86,300)	$	(61,513)

Notes to the Consolidated Financial Statements 126

Algonquin Power & Utilities Corp.

Notes to the Consolidated Financial Statements

December 31, 2023 and 2022

(in thousands of U.S. dollars, except as noted and per share amounts)

18.Income taxes (continued)

On December 27, 2023, the government of Bermuda enacted the Bermuda Corporate Income Tax Act 2023, setting a 15% corporate income tax rate effective for fiscal years commencing January 1, 2025. The Bermuda Corporate Income Tax Act 2023 includes various transition adjustments that may affect the recognition of deferred taxes and as such were considered as part of the initial measurement in the period that includes the December 2023 enactment date. No deferred taxes were required to be recognized as at December 31, 2023.

For the years ended December 31, 2023 and 2022, earnings (loss) before income taxes consist of the following:

	2023		2022
Canada (1)	$	(259,141)	$	(363,050)
U.S.	102,469		(37,322)
Other regions	37,067		30,704
	$	(119,605)	$	(369,668)

(1)Inclusive of fair value gain (loss) on investments carried at fair value (note 8)

Income tax expense (recovery) attributable to income (loss) consists of: 

	Current		Deferred		Total
Year ended December 31, 2023
Canada	$	4,352	$	(59,488)	$	(55,136)
United States	(14,820)		(23,099)		(37,919)
Other regions	728		6,027		6,755
	$	(9,740)	$	(76,560)	$	(86,300)
Year ended December 31, 2022
Canada	$	4,184	$	(74,595)	$	(70,411)
United States	1,579		6,183		7,762
Other regions	2,080		(944)		1,136
	$	7,843	$	(69,356)	$	(61,513)

Notes to the Consolidated Financial Statements 127

Algonquin Power & Utilities Corp.

Notes to the Consolidated Financial Statements

December 31, 2023 and 2022

(in thousands of U.S. dollars, except as noted and per share amounts)

18.Income taxes (continued)

The tax effect of temporary differences between the consolidated financial statement carrying amounts of assets and liabilities and their respective tax bases that give rise to significant portions of the deferred tax assets and deferred tax liabilities as of December 31, 2023 and 2022 are presented below:

	2023		2022
Deferred tax assets:
Non-capital loss, investment tax credits, currently non-deductible interest expenses, and financing costs	$	1,030,801	$	878,000
Pension and OPEB	7,370		16,845
Environmental obligation	11,692		12,118
Regulatory liabilities	180,371		156,285
Other	72,109		61,917
Total deferred income tax assets	$	1,302,343	$	1,125,165
Less: valuation allowance	(97,344)		(107,583)
Total deferred tax assets	$	1,204,999	$	1,017,582
Deferred tax liabilities:
Property, plant and equipment	$	883,447	$	846,331
Outside basis differentials	364,511		315,581
Regulatory accounts	317,820		303,059
Other	59,640		33,834
Total deferred tax liabilities	$	1,625,418	$	1,498,805
Net deferred tax liabilities	$	(420,419)	$	(481,223)
Consolidated balance sheets classification:
Deferred tax assets	$	158,483	$	84,416
Deferred tax liabilities	(578,902)		(565,639)
Net deferred tax liabilities	$	(420,419)	$	(481,223)

The valuation allowance for deferred tax assets as of December 31, 2023 was $97,344 (2022 - $107,583). The valuation allowance primarily relates to operating losses that, in the judgment of management, are not more likely than not to be realized for the Renewable Energy Group.

The U.S. entities in the Renewable Energy Group continue to be in an overall deferred tax asset position as at December 31, 2023. In the course of assessing the U.S. deferred tax assets in the Renewable Energy Group, management concluded, similar to 2022, that it was not probable that the U.S. business of the Renewable Energy Group would generate sufficient taxable income to realize the benefit of the deferred tax assets of such group (with the exception of certain transferable tax credits). Management’s conclusion is based on the balance of all available positive and negative evidence applicable to the Renewable Energy Group. 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.

The Company’s overall deferred tax asset position related to Canadian attributes increased from $83,434 to $151,759 for the year ended December 31, 2023, primarily due to ongoing interest and financing expenses attributable to the Canadian entities and the decrease in the value of the Company’s investment in Atlantica. As at December 31, 2023, it is considered more likely than not that there will be sufficient taxable income in the future that will allow realization of these deferred tax assets. The Company considered all evidence, both positive and negative, including the announcement of the sale of the renewable energy business, the availability of tax planning strategies, and the carryforward period of its Canadian net operating losses in making this assessment. The Company will continue to monitor this position at each balance sheet date.

Notes to the Consolidated Financial Statements 128

Algonquin Power & Utilities Corp.

Notes to the Consolidated Financial Statements

December 31, 2023 and 2022

(in thousands of U.S. dollars, except as noted and per share amounts)

18.Income taxes (continued)

The following table illustrates the annual movement in the deferred tax valuation allowance: 

	2023		2022
Beginning balance	$	107,583	$	27,471
Charged to income tax expense	10,786		41,702
Charged (reduction) to OCI	(16,696)		40,613
Reductions to other accounts	(4,329)		(2,203)
Ending balance	$	97,344	$	107,583

As of December 31, 2023, the Company had non-capital losses carried forward and tax credits available to reduce future years' taxable income, which expire as follows: 

Non-capital loss carryforward and credits	2024—2028		2029+		Total
Canada	$	3,339	$	913,781	$	917,120
US	8,441		1,897,609		1,906,050
Total non-capital loss carryforward	$	11,780	$	2,811,390	$	2,823,170
Tax credits	$	3,359	$	200,772	$	204,131

The Company has provided for deferred income taxes for the estimated tax cost of distributed earnings of certain of its subsidiaries. Deferred income taxes have not been provided on approximately $908,449 of undistributed earnings of certain foreign subsidiaries, as the Company has concluded that such earnings are indefinitely reinvested and should not give rise to additional tax liabilities. A determination of the amount of the unrecognized tax liability relating to the remittance of such undistributed earnings is not practicable.

19.Other net losses

Other net losses consist of the following:

	2023		2022
Acquisition and transition-related costs	$	—	$	6,834
Kentucky termination costs (a)	46,527		10,608
Acquisition-related settlement payment (b)	(11,983)		—
Securitization write-off (c)	63,495		—
Renewable energy business sale costs (d)	12,506		—
Loss on redemption of long-term note (e)	8,532		—
Other (f)	13,812		3,949
	$	132,889	$	21,391

(a)Kentucky termination costs

The loss related to the termination of the Kentucky Power Transaction includes $38,795 for the write-off of capitalized costs, which are primarily related to the implementation of an enterprise software solution. The remaining amount relates to the transaction costs, severance costs and other termination costs. In 2022, the Company incurred $10,608 in anticipation of the Kentucky Power Transaction.

(b)Acquisition-related settlement payment

During the year, the Company received $12,814 as an acquisition-related settlement payment in connection with the Suralis acquisition. The Company also incurred legal fees of $831 in relation to this settlement.

Notes to the Consolidated Financial Statements 129

Algonquin Power & Utilities Corp.

Notes to the Consolidated Financial Statements

December 31, 2023 and 2022

(in thousands of U.S. dollars, except as noted and per share amounts)

19.Other net losses (continued)

(c)Securitization write-off

During the year, the Company has written off $63,495 relating to the portion of additional securitization costs of Empire Electric that were not allowed as per the Securitization Statute (note 7(a)).

(d)Renewable energy business sale costs

The Company announced that it is pursuing a sale of its renewable energy business. The Company incurred costs of $12,506 related to this process in 2023.

(e)Loss on redemption of long-term note

During Q4, 2023, the Company redeemed subordinated unsecured long-term note (note 9(f)) and incurred loss on redemption of $8,532.

(f)Other

Other losses for the year consist primarily of provisions on litigation matters, executive severance costs, the Series C preferred share redemption loss and other miscellaneous write-offs.

20.Basic and diluted net earnings (loss) per share

Basic and diluted earnings (loss) per share have been calculated on the basis of net earnings attributable to the common shareholders of the Company and the weighted average number of common shares and bonus deferral restricted share units outstanding. Diluted net earnings per share is computed using the weighted average number of common shares, additional shares issued subsequent to year-end under the dividend reinvestment plan, PSUs, RSUs and DSUs outstanding during the year and, if dilutive, potential incremental common shares related to the convertible debentures or resulting from the application of the treasury stock method to outstanding share options and Green Equity Units (note 9(c)).

The reconciliation of the net earnings (loss) and the weighted average shares used in the computation of basic and diluted earnings (loss) per share are as follows:

	2023		2022
Net earnings (loss) attributable to shareholders of AQN	$	28,674	$	(211,989)
Preferred shares, Series A dividend	4,586		4,786
Preferred shares, Series D dividend	3,770		3,934
Net earnings (loss) attributable to common shareholders of AQN – basic and diluted	$	20,318	$	(220,709)
Weighted average number of shares
Basic	688,738,717		677,862,207
Effect of dilutive securities	2,024,509		—
Diluted	690,763,226		677,862,207

This calculation of diluted shares excludes the potential impact of the Green Equity Units and 5,699,593 potential incremental shares that may become issuable pursuant to outstanding securities of the Company for the year ended December 31, 2023, as they are anti-dilutive. This calculation of diluted shares for the year ended December 31, 2022 excludes all potential incremental shares that may become issuable pursuant to outstanding securities of the Company as they are anti-dilutive.

Notes to the Consolidated Financial Statements 130

Algonquin Power & Utilities Corp.

Notes to the Consolidated Financial Statements

December 31, 2023 and 2022

(in thousands of U.S. dollars, except as noted and per share amounts)

21.Segmented information

The Company is managed under two primary business units consisting of the Regulated Services Group and the Renewable Energy Group. The two business units are the two segments of the Company.

The Regulated Services Group, the Company’s regulated operating unit, owns and operates a portfolio of electric, water distribution and wastewater collection, and natural gas utility systems and transmission operations in the United States, Canada, Bermuda and Chile; the Renewable Energy Group, the Company’s non-regulated operating unit, owns and operates, or has investments in, a diversified portfolio of renewable and thermal energy generation assets.

For purposes of evaluating the performance of the business units, the Company allocates the realized portion of any gains or losses on financial instruments to the specific business units. Dividend income from Atlantica and AYES Canada are included in the operations of the Renewable Energy Group, while interest income from SAWS is included in the operations of the Regulated Services Group. Equity method gains and losses are included in the operations of the Regulated Services Group or Renewable Energy Group based on the nature of the activities of the investees. The change in value of investments carried at fair value and unrealized portion of any gains or losses on derivative instruments not designated in a hedging relationship are not considered in management’s evaluation of divisional performance and are therefore allocated and reported under corporate.

	Year ended December 31, 2023
	Regulated Services Group		Renewable Energy Group		Corporate		Total
Revenue (1)(2)	$	2,315,722	$	296,314	$	—	$	2,612,036
Other revenue	51,137		33,395		1,447		85,979
Fuel, power and water purchased	716,446		19,499		—		735,945
Net revenue	1,650,413		310,210		1,447		1,962,070
Operating expenses	786,608		119,013		1,364		906,985
Administrative expenses	46,386		36,554		7,419		90,359
Depreciation and amortization	346,188		119,576		1,232		466,996
Asset impairment charge	—		23,492		—		23,492
Loss on foreign exchange	—		—		8,359		8,359
Operating income (loss)	471,231		11,575		(16,927)		465,879
Interest expense	(160,998)		(61,261)		(131,397)		(353,656)
Income (loss) from long-term investments	44,953		102,188		(230,705)		(83,564)
Other expenses	(121,146)		(4,002)		(23,116)		(148,264)
Earnings (loss) before income taxes	$	234,040	$	48,500	$	(402,145)	$	(119,605)
Property, plant and equipment	$	8,945,637	$	3,539,069	$	32,744	$	12,517,450
Investments carried at fair value	1,962		1,113,767		—		1,115,729
Equity-method investees	112,180		343,712		501		456,393
Total assets	12,658,955		5,367,011		347,995		18,373,961
Capital expenditures	$	816,788	$	209,383	$	—	$	1,026,171

(1)Renewable Energy Group revenue includes $5,695 related to net hedging gain from energy derivative contracts and availability credits for the year ended December 31, 2023 that do not represent revenue recognized from contracts with customers.

(2) Regulated Services Group revenue includes $32,839 related to alternative revenue programs for the year ended December 31, 2023 that do not represent revenue recognized from contracts with customers.

Notes to the Consolidated Financial Statements 131

Algonquin Power & Utilities Corp.

Notes to the Consolidated Financial Statements

December 31, 2023 and 2022

(in thousands of U.S. dollars, except as noted and per share amounts)

21.Segmented information (continued)

	Year ended December 31, 2022
	Regulated Services Group		Renewable Energy Group		Corporate		Total
Revenue (1)(2)	$	2,330,039	$	350,797	$	—	$	2,680,836
Other revenue	54,229		28,447		1,501		84,177
Fuel and power purchased	824,670		41,684		—		866,354
Net revenue	1,559,598		337,560		1,501		1,898,659
Operating expenses	736,515		114,463		511		851,489
Administrative expenses	46,484		26,424		7,324		80,232
Depreciation and amortization	317,300		137,203		1,017		455,520
Asset impairment charge	—		159,568		—		159,568
Loss on foreign exchange	—		—		13,833		13,833
	459,299		(100,098)		(21,184)		338,017
Gain on sale of renewable assets	—		64,028		—		64,028
Operating income (loss)	459,299		(36,070)		(21,184)		402,045
Interest expense	(113,482)		(64,285)		(100,807)		(278,574)
Income (loss) from long-term investments	21,884		15,254		(502,344)		(465,206)
Other expenses	(14,765)		(570)		(12,598)		(27,933)
Earnings (loss) before income taxes	$	352,936	$	(85,671)	$	(636,933)	$	(369,668)
Property, plant and equipment	$	8,554,938	$	3,360,687	$	29,260	$	11,944,885
Investments carried at fair value	1,984		1,342,223		—		1,344,207
Equity-method investees	56,199		310,103		15,500		381,802
Total assets	12,109,575		5,251,933		266,105		17,627,613
Capital expenditures	$	908,676	$	180,348	$	—	$	1,089,024

(1)Renewable Energy Group revenue includes $63,717 related to net hedging loss from energy derivative contracts for the year ended December 31, 2022 that do not represent revenue recognized from contracts with customers.

(2) Regulated Services Group revenue includes $21,640 related to alternative revenue programs for the year ended December 31, 2022 that do not represent revenue recognized from contracts with customers.

The majority of non-regulated energy sales are earned from contracts with large public utilities. The Company has sought to mitigate its credit risk by selling energy to large utilities in various North American locations. None of the utilities contribute more than 10% of total revenue.

Notes to the Consolidated Financial Statements 132

Algonquin Power & Utilities Corp.

Notes to the Consolidated Financial Statements

December 31, 2023 and 2022

(in thousands of U.S. dollars, except as noted and per share amounts)

21.Segmented information (continued)

AQN operates in the independent power and utility industries in the United States, Canada and other regions. Information on operations by geographic area is as follows:

	2023		2022
Revenue
United States	$	2,169,239	$	2,232,817
Canada	162,740		175,005
Other regions	366,036		357,191
	$	2,698,015	$	2,765,013
Property, plant and equipment
United States	$	10,826,738	$	10,351,736
Canada	924,389		848,560
Other regions	766,323		744,589
	$	12,517,450	$	11,944,885
Intangible assets
United States	$	18,666	$	18,818
Canada	18,111		19,038
Other regions	57,161		58,827
	$	93,938	$	96,683

Revenue is attributed to the regions based on the location of the underlying generating and utility facilities.

22.Commitments and contingencies

(a)Contingencies

AQN and its subsidiaries are involved in various claims and litigation arising out of the ordinary course and conduct of its business. Although such matters cannot be predicted with certainty, management does not consider AQN’s exposure to such litigation to be material to these consolidated financial statements. Accruals for any contingencies related to these items are recorded in the consolidated financial statements at the time it is concluded that its occurrence is probable and the related liability is estimable.

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 21 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. Fourteen 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 14 lawsuits also alleges the wrongful death of an individual and various subrogation claims on behalf of insurance companies). On March 6, 2024, a trial commenced in Los Angeles County Superior Court on four bellwether cases with respect to inverse condemnation liability only. If the Company’s subsidiaries were found liable in those cases, the damages, if any, would not be determined at this trial. In another lawsuit, County of Mono, Antelope Valley Fire Protection District 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 six other lawsuits, insurance companies allege inverse condemnation and negligence and seek recovery of amounts paid and to be paid to their insureds. The likelihood of success in these lawsuits is uncertain.

Notes to the Consolidated Financial Statements 133

Algonquin Power & Utilities Corp.

Notes to the Consolidated Financial Statements

December 31, 2023 and 2022

(in thousands of U.S. dollars, except as noted and per share amounts)

22.Commitments and contingencies (continued)

(a)Contingencies (continued)

In 2023, Liberty CalPeco accrued estimated losses of $66,000 for claims related to the Mountain View Fire, against which Liberty CalPeco has recorded expected recoveries from insurance of $66,000. The resulting net charge to earnings was $nil. The estimate of losses is subject to change as additional information becomes available. The actual amount of losses may be higher or lower than these estimates. While the Company may incur a material loss in excess of the amount accrued, the Company cannot estimate the upper end of the range of reasonably possible losses that may be incurred. The Company has wildfire liability insurance that is expected to apply up to applicable policy limits.

(b)Commitments

In addition to the commitments related to the development projects disclosed in note 8, the following significant commitments exist as of December 31, 2023.

AQN has outstanding purchase commitments for power purchases, natural gas supply and service agreements, service agreements, capital project commitments, land easements and other commitments.

Detailed below are estimates of future commitments under these arrangements: 

	Year 1		Year 2		Year 3		Year 4		Year 5		Thereafter		Total
Power purchase (1)	$	55,312	$	33,869	$	12,274	$	12,520	$	12,768	$	129,818	$	256,561
Natural gas supply and service agreements (2)	121,188		71,949		42,643		33,215		30,803		154,757		454,555
Service agreements	73,687		61,889		56,591		53,140		52,898		259,510		557,715
Capital projects	5,598		—		—		—		—		—		5,598
Land easements and other	16,437		15,057		15,269		15,425		15,639		536,129		613,956
Total	$	272,222	$	182,764	$	126,777	$	114,300	$	112,108	$	1,080,214	$	1,888,385

(1)    Power purchase: AQN’s electric distribution facilities have commitments to purchase physical quantities of power for load serving requirements. The commitment amounts included in the table above are based on market prices as of December 31, 2023. However, the effects of purchased power unit cost adjustments are mitigated through a purchased power rate-adjustment mechanism.

(2)Natural gas supply and service agreements: AQN’s natural gas distribution facilities and thermal generation facilities have commitments to purchase physical quantities of natural gas under contracts for purposes of load serving requirements and of generating power.

Notes to the Consolidated Financial Statements 134

Algonquin Power & Utilities Corp.

Notes to the Consolidated Financial Statements

December 31, 2023 and 2022

(in thousands of U.S. dollars, except as noted and per share amounts)

23.Non-cash operating items

The changes in non-cash operating items consist of the following:

	2023		2022
Accounts receivable	$	3,863	$	(124,631)
Fuel and natural gas in storage	46,368		(21,140)
Supplies and consumables inventory	(48,539)		(24,088)
Income taxes recoverable	(2,889)		549
Prepaid expenses	(13,218)		(4,269)
Accounts payable	23,847		24,395
Accrued liabilities	(488)		127,076
Current income tax liability	1,096		(2,741)
Asset retirements and environmental obligations	(1,015)		(22,342)
Net regulatory assets and liabilities	(95,361)		(174,427)
	$	(86,336)	$	(221,618)

Notes to the Consolidated Financial Statements 135

Algonquin Power & Utilities Corp.

Notes to the Consolidated Financial Statements

December 31, 2023 and 2022

(in thousands of U.S. dollars, except as noted and per share amounts)

24.Financial instruments

(a)Fair value of financial instruments

December 31, 2023	Carrying amount		Fair value		Level 1		Level 2		Level 3
Long-term investments carried at fair value	$	1,115,729	$	1,115,729	$	1,054,665	$	—	$	61,064
Development loans and other receivables	158,110		155,735		—		155,735		—
Derivative instruments:
Interest rate swap designated as a hedge	72,936		72,936		—		72,936		—
Interest rate cap not designated as a hedge	1,854		1,854		—		1,854		—
Congestion revenue rights not designated as a cash flow hedge	8,458		8,458		—		—		8,458
Total derivative instruments	83,248		83,248		—		74,790		8,458
Total financial assets	$	1,357,087	$	1,354,712	$	1,054,665	$	230,525	$	69,522
Long-term debt	$	8,516,030	$	7,423,318	$	2,532,608	$	4,890,710	$	—
Notes payable to related party	25,808		15,320		—		15,320		—
Convertible debentures	230		276		276		—		—
Derivative instruments:
Energy contracts designated as a cash flow hedge	68,070		68,070		—		—		68,070
Energy contracts not designated as a cash flow hedge	5,593		5,593		—		—		5,593
Cross-currency swap designated as a net investment hedge	10,533		10,533		—		10,533		—
Currency forward contract designated as hedge	6,779		6,779		—		6,779		—
Interest rate swaps designated as a hedge	11,790		11,790		—		11,790		—
Cross currency swap designated as a cash flow hedge	5,547		5,547		—		5,547		—
Commodity contracts for regulated operations	2,564		2,564		—		2,564		—
Total derivative instruments	110,876		110,876		—		37,213		73,663
Total financial liabilities	$	8,652,944	$	7,549,790	$	2,532,884	$	4,943,243	$	73,663

Notes to the Consolidated Financial Statements 136

Algonquin Power & Utilities Corp.

Notes to the Consolidated Financial Statements

December 31, 2023 and 2022

(in thousands of U.S. dollars, except as noted and per share amounts)

24.Financial instruments (continued)

(a)Fair value of financial instruments (continued)

December 31, 2022	Carrying amount		Fair value		Level 1		Level 2		Level 3
Long-term investment carried at fair value	$	1,344,207	$	1,344,221	$	1,270,138	$	—	$	74,083
Development loans and other receivables	53,680		50,300		—		50,300		—
Derivative instruments:
Energy contracts not designated as a cash flow hedge	393		393		—		—		393
Interest rate swap designated as a hedge	69,188		69,188		—		69,188		—
Currency forward contract not designated as a hedge	2,659		2,659		—		2,659		—
Congestion revenue rights not designated as a cash flow hedge	10,110		10,110		—		—		10,110
Cross-currency swap designated as a net investment hedge	1,267		1,267		—		1,267		—
Commodity contracts for regulated operations	283		283		—		283		—
Total derivative instruments	83,900		83,900		—		73,397		10,503
Total financial assets	$	1,481,787	$	1,478,421	$	1,270,138	$	123,697	$	84,586
Long-term debt	$	7,512,017	$	6,699,031	$	2,623,628	$	4,075,403	$	—
Notes payable to related party	25,808		15,180		—		15,180		—
Convertible debentures	245		276		276		—		—
Preferred shares, Series C	12,072		11,675		—		11,675		—
Derivative instruments:
Energy contracts designated as a cash flow hedge	120,284		120,284		—		—		120,284
Energy contracts not designated as a cash flow hedge	8,617		8,617		—		—		8,617
Cross-currency swap designated as a net investment hedge	24,371		24,371		—		24,371		—
Cross-currency swap designated as a cash flow hedge	15,435		15,435		—		15,435		—
Commodity contracts for regulated operations	1,614		1,614		—		1,614		—
Total derivative instruments	170,321		170,321		—		41,420		128,901
Total financial liabilities	$	7,720,463	$	6,896,483	$	2,623,904	$	4,143,678	$	128,901

The Company has determined that the carrying value of its short-term financial assets and liabilities approximates fair value as ofDecember 31, 2023 and 2022 due to the short-term maturity of these instruments.

Notes to the Consolidated Financial Statements 137

Algonquin Power & Utilities Corp.

Notes to the Consolidated Financial Statements

December 31, 2023 and 2022

(in thousands of U.S. dollars, except as noted and per share amounts)

24.Financial instruments (continued)

(a)Fair value of financial instruments (continued)

The fair value of the investment in Atlantica (Level 1) is measured at the closing price on the NASDAQ stock exchange.

The fair value of development loans and other receivables (Level 2) is determined using a discounted cash flow method, using estimated current market rates for similar instruments adjusted for estimated credit risk as determined by management. 

The Company’s Level 1 fair value of long-term debt is measured at the closing price on the NYSE and the Canadian over-the-counter closing price. The Company’s Level 2 fair value of long-term debt at fixed interest rates and notes payable to related party have been determined using a discounted cash flow method and current interest rates. The Company’s Level 2 fair value of convertible debentures has been determined as the greater of their face value and the quoted value of AQN’s common shares on a converted basis.

The Company’s Level 2 fair value derivative instruments primarily consist of swaps, options, rights, caps, subscription agreements and forward physical derivatives where market data for pricing inputs are observable. Level 2 pricing inputs are obtained from various market indices and utilize discounting based on quoted interest rate curves, which are observable in the marketplace.

The Company’s Level 3 instruments consist of energy contracts for electricity sales, congestion revenue rights (“CRRs”) and the fair value of the Company’s investment in AYES Canada. The significant unobservable inputs used in the fair value measurement of energy contracts are the internally developed forward market prices ranging from $26.32 to $144.02 with a weighted average of $38.44 as of December 31, 2023. The weighted average forward market prices are developed based on the quantity of energy expected to be sold monthly and the expected forward price during that month. The change in the fair value of the energy contracts is detailed in notes 24(b)(ii) and 24(b)(iv). The significant unobservable inputs used in the fair value measurement of CRRs are recent CRR auction prices ranging from $nil to $$52.02 with a weighted average of $5.69 as of December 31, 2023. The fair value of the investment in AYES Canada is determined using a discounted cash flow approach combined with a binomial tree approach. The significant unobservable inputs used in the fair value measurement of the Company’s AYES Canada investment are the expected cash flows, the discount rates applied to these cash flows ranging from 8.00%to 8.50% with a weighted average of 8.27%, and the expected volatility of Atlantica’s share price ranging from 27.47%to 33.19%as of December 31, 2023. Significant increases (decreases) in expected cash flows or increases (decreases) in discount rate in isolation would have resulted in a significantly lower (higher) fair value measurement.

(b)Derivative instruments

Derivative instruments are recognized on the consolidated balance sheets as either assets or liabilities and measured at fair value at each reporting period.

(i)Commodity derivatives – regulated accounting

The Company uses derivative financial instruments to reduce the cash flow variability associated with the purchase price for a portion of future natural gas purchases associated with its regulated natural gas and electric service territories. The Company’s strategy is to minimize fluctuations in natural gas sale prices to regulated customers. As at December 31, 2023, the commodity volume, in dekatherms, associated with the above derivative contracts is 2,117,039.

Notes to the Consolidated Financial Statements 138

Algonquin Power & Utilities Corp.

Notes to the Consolidated Financial Statements

December 31, 2023 and 2022

(in thousands of U.S. dollars, except as noted and per share amounts)

24.Financial instruments (continued)

(b)Derivative instruments (continued)

(i)Commodity derivatives – regulated accounting (continued)

The accounting for these derivative instruments is subject to guidance for rate-regulated enterprises. Therefore, the fair value of these derivatives is recorded as current or long-term assets and liabilities, with offsetting positions recorded as regulatory assets and regulatory liabilities in the consolidated balance sheets. Most of the gains or losses on the settlement of these contracts are included in the calculation of the fuel and commodity costs adjustments (note 7(a)). As a result, the changes in fair value of these natural gas derivative contracts and their offsetting adjustment to regulatory assets and liabilities had no earnings impact.

(ii)Cash flow hedges

The Company reduces the price risk on the expected future sale of power generation by entering into the following long-term energy derivative contracts. 

Notional quantity (MW-hrs)	Expiry	Receive average prices (per MW-hr)	Pay floating price (per MW-hr)
353,597	December 2028	$29.19	PJM Western HUB
1,492,926	December 2027	$21.34	NI HUB
1,332,645	December 2027	$36.46	ERCOT North HUB
3,534,802	September 2030	$24.54	Illinois Hub

The Company mitigates the risk that interest rates will increase over the life of certain term loan facilities by entering into the following interest rate swap contracts. For an interest rate swap or cross-currency interest rate swap designated as hedging the exposure to variable cash flows of a future transaction, the effective portion of this derivative's gain or loss is initially reported as a component of other comprehensive income (loss) and subsequently reclassified into earnings once the future transaction impacts earnings. Amounts for interest rate contracts are reclassified to earnings as interest expense over the term of the related debt.

Derivative	Notional quantity		Expiry	Hedged item
Forward-starting interest rate swap	$	350,000	July 2029	$350,000 subordinated unsecured notes
Cross-currency interest rate swap	C$	400,000	January 2032	C$400,000 subordinated unsecured notes
Forward-starting interest rate swap	$	750,000	April 2032	$750,000 subordinated unsecured notes
Forward-starting interest rate swap	$	575,000	June 2026	First $575,000 of the expected $1,150,000 senior unsecured notes issuance

Notes to the Consolidated Financial Statements 139

Algonquin Power & Utilities Corp.

Notes to the Consolidated Financial Statements

December 31, 2023 and 2022

(in thousands of U.S. dollars, except as noted and per share amounts)

24.Financial instruments (continued)

(b)Derivative instruments (continued)

(ii)Cash flow hedges (continued)

The following table summarizes OCI attributable to derivative financial instruments designated as a cash flow hedge: 

	2023		2022
Effective portion of cash flow hedge	$	57,351	$	(128,838)
Amortization of cash flow hedge	(6,173)		(12,180)
Amounts reclassified from AOCI	8,309		46,723
OCI attributable to shareholders of AQN	$	59,487	$	(94,295)

The Company expects $25,895 of unrealized losses currently in AOCI to be reclassified, net of taxes into non-regulated energy sales, investment loss, interest expense and derivative gains, respectively, within the next 12 months, as the underlying hedged transactions settle.

(iii)Foreign exchange hedge of net investment in foreign operation

The functional currency of most of AQN's operations is the U.S. dollar. The Company designates obligations denominated in Canadian dollars as a hedge of the foreign currency exposure of its net investment in its Canadian investments and subsidiaries. The related foreign currency transaction gain or loss designated as, and effective as, a hedge of the net investment in a foreign operation is reported in the same manner as the translation adjustment (in OCI) related to the net investment. A foreign currency loss of$12,330 for the year ended December 31, 2023 (2022 - gain of $2,262) was recorded in OCI.

On May 23, 2019, the Company entered into a cross-currency swap, coterminous with the subordinated unsecured notes issued on such date, to effectively convert the $350,000 U.S. dollar-denominated offering into Canadian dollars. The change in the carrying amount of the notes due to changes in spot exchange rates is recognized each period in the consolidated statements of operations as gain (loss) on foreign exchange. The Company designated the entire notional amount of the cross-currency fixed-for-fixed interest rate swap as a hedge of the foreign currency exposure related to cash flows for the interest and principal repayments on the notes. Upon the change in functional currency of AQN to the U.S. dollar on January 1, 2020, this hedge was dedesignated. The OCI related to this hedge will be amortized into earnings in the period that future interest payments affect earnings over the remaining life of the original hedge. The Company redesignated this swap as a hedge of AQN's net investment in its Canadian subsidiaries.

The related foreign currency transaction gain or loss designated as a hedge of the net investment in a foreign operation is reported in the same manner as the translation adjustment (in OCI) related to the net investment. The fair value of the derivative on the redesignation date will be amortized over the remaining life of the original hedge. A foreign currency gain of $6,976 for the year ended December 31, 2023 (2022 - gain of $22,091) was recorded in OCI.

Canadian operations

The Company is exposed to currency fluctuations from its Canadian-based operations. AQN manages this risk primarily through the use of natural hedges by using Canadian long-term debt to finance its Canadian operations and a combination of foreign exchange forward contracts and spot purchases.

The Company’s Canadian operations are determined to have the Canadian dollar as their functional currency and are exposed to currency fluctuations from their U.S. dollar transactions. The Company designates obligations denominated in U.S. dollars as a hedge of the foreign currency exposure of its net investment in its U.S. investments and subsidiaries. The related foreign currency transaction gain or loss designated as, and effective as, a hedge of the net investment in a foreign operation is reported in the same manner as the translation adjustment (in OCI) related to the net investment. A foreign currency gain of $606 for the year ended December 31, 2023 (2022 - loss of $18,561) was recorded in OCI.

Notes to the Consolidated Financial Statements 140

Algonquin Power & Utilities Corp.

Notes to the Consolidated Financial Statements

December 31, 2023 and 2022

(in thousands of U.S. dollars, except as noted and per share amounts)

24.Financial instruments (continued)

(b)Derivative instruments (continued)

(iii)Foreign exchange hedge of net investment in foreign operation (continued)

Canadian operations (continued)

The Company is party to C$300,000 (2022 - C$300,000) fixed-for-fixed cross-currency swaps to effectively convert Canadian dollar debentures into U.S. dollars. In February 2022, the Company settled the cross-currency swap related to its C$200,000 (2021 - C$150,000) debenture that was repaid. The Company designated the entire notional amount of the cross-currency fixed-for-fixed interest rate swap and related short-term U.S. dollar payables created by the monthly accruals of the swap settlement as a hedge of the foreign currency exposure of its net investment in the Renewable Energy Group's U.S. operations. The gain or loss related to the fair value changes of the swap and the related foreign currency gains and losses on the U.S. dollar accruals that are designated as, and are effective as, a hedge of the net investment in a foreign operation are reported in the same manner as the translation adjustment (in OCI) related to the net investment. A gain of $5,959 for the year ended December 31, 2023 (2022 - loss of $11,082) was recorded in OCI.

On April 9, 2021, the Renewable Energy Group entered into a fixed-for-fixed cross-currency interest rate swap, coterminous with the senior unsecured debentures issued on such date, to effectively convert the C$400,000 Canadian-dollar-denominated offering into U.S. dollars. The Renewable Energy Group designated the entire notional amount of the fixed-for-fixed cross-currency interest rate swap and related short-term U.S. dollar payables created by the monthly accruals of the swap settlement as a hedge of the foreign currency exposure of its net investment in the Renewable Energy Group's U.S. operations. The gain or loss related to the fair value changes of the swap and the related foreign currency gains and losses on the U.S. dollar accruals that are designated as, and are effective as, a hedge of the net investment in a foreign operation are reported in the same manner as the translation adjustment (in OCI) related to the net investment. A gain of $8,420 for the year ended December 31, 2023(2022 - loss of $13,374) was recorded in OCI.

Chilean operations

The Company is exposed to currency fluctuations from its Chilean-based operations. The Company's Chilean operations are determined to have the Chilean peso as their functional currency. Chilean long-term debt used to finance the operations is denominated in Chilean Unidad de Fomento.

(iv)Other derivatives and risk management

In the normal course of business, the Company is exposed to financial risks that potentially impact its operating results. The Company employs risk management strategies with a view to mitigating these risks to the extent possible on a cost-effective basis. Derivative financial instruments are used to manage certain exposures to fluctuations in exchange rates, interest rates and commodity prices. The Company does not enter into derivative financial agreements for speculative purposes. For derivatives that are not designated as hedges, the changes in the fair value are immediately recognized in earnings (loss).

The Company was party to an interest rate cap agreement in the amount of $390,000 for the period between January 15, 2023 and January 15, 2024. On September 29, 2023, the Company entered into a new interest rate cap agreement in the amount of $390,000 million for the period between January 15, 2024 and June 17, 2024.

The Company was party to interest rate swaps with a notional quantity of C$489,506 to mitigate the interest rate risk related to debt at its Blue Hill Wind Facility. The contract was novated upon the sale of the Blue Hill Wind Facility in 2022. A recognized loss of C$9,732 on the derivative was recorded as a reduction of the gain on sale of renewable assets on the audited consolidated statements of operations.

The Company mitigates the volatility of energy congestion charges at the ERCOT transmission grid by entering into CRRs, which as of December 31, 2023 had notional quantity of 5,486,961 MW-hours at prices ranging from $0.55 per MW-hr to $24.88 per MW-hr with a weighted average of $5.16 per MW-hr for January 2024 to June 2026. These CRRs are not designated as an accounting hedge.

Notes to the Consolidated Financial Statements 141

Algonquin Power & Utilities Corp.

Notes to the Consolidated Financial Statements

December 31, 2023 and 2022

(in thousands of U.S. dollars, except as noted and per share amounts)

24.Financial instruments (continued)

(b)Derivative instruments (continued)

(iv)Other derivatives and risk management (continued)

The Company mitigates the price risk on the expected future sale of power generation of one of its solar facilities through a long-term energy derivative contract with a notional quantity of 516,202 MW-hours, a price of $25.15 per MW-hr and expiring in August 2030 as an economic hedge to the price of energy sales. The derivative contract is not designated as an accounting hedge.

The effects on the consolidated statements of operations of derivative financial instruments not designated as hedges consist of the following:

	2023		2022
Unrealized gain (loss) on derivative financial instruments:
Energy derivative contracts	$	(372)	$	(945)
Commodity contracts	411		185
Total unrealized gain (loss) on derivative financial instruments	$	39	$	(760)
Realized gain (loss) on derivative financial instruments:
Energy derivative contracts	$	(4,896)	$	6,939
Interest rate swaps	—		(7,185)
Total realized loss on derivative financial instruments	$	(4,896)	$	(246)
Loss on derivative financial instruments not accounted for as hedges	(4,857)		(1,006)
Amortization of AOCI gains frozen as a result of hedge dedesignation	3,989		3,465
	$	(868)	$	2,459
Consolidated statements of operations classification:
Gain on derivative financial instruments	$	4,564	$	4,408
Renewable energy sales	(5,432)		5,236
Reduction to gain on sale of renewable assets	—		(7,185)
	$	(868)	$	2,459

(c)Supplier financing programs

In the normal course of business, the Company enters into supplier financing programs under which the suppliers can voluntarily elect to sell their receivables. The Company agrees to pay, on the invoice maturity date, the stated amount of the invoices that the Company has confirmed through the execution of bills of exchange. The terms of the trade payable arrangement are consistent with customary industry practice and are not impacted by the supplier’s decision to sell amounts under these arrangements.

The roll forwards of the Company's outstanding obligations confirmed as valid under its supplier finance programs for years ended December 31, 2023 and 2022, are as follows:

	2023		2022
Confirmed obligations outstanding at the beginning of the year	$	16,785	$	49,910
Invoices confirmed during the year	90,780		16,785
Confirmed invoices paid during the year	(45,392)		(49,910)
Confirmed obligations outstanding at the end of the year	$	62,173	$	16,785

Notes to the Consolidated Financial Statements 142

Algonquin Power & Utilities Corp.

Notes to the Consolidated Financial Statements

December 31, 2023 and 2022

(in thousands of U.S. dollars, except as noted and per share amounts)

24.Financial instruments (continued)

(d)Risk management

In addition to the risk management strategies described above, the Company manages exposure to risks arising from financial instruments, including credit risk and liquidity risk.

Credit risk

Credit risk is the risk of an unexpected loss if a customer or counterparty to a financial instrument fails to meet its contractual obligations. The Company’s financial instruments that are exposed to concentrations of credit risk are primarily cash and cash equivalents, accounts receivable, notes receivable and derivative instruments. The Company limits its exposure to credit risk with respect to cash equivalents by ensuring available cash is deposited with its senior lenders, all of which have a credit rating of A or better. The Company does not consider the risk associated with the accounts receivable to be significant as the majority of revenue from power generation is earned from large utility customers having a credit rating of Baa2 or better by Moody's, or BBB or higher by S&P, or BBB or higher by DBRS. Revenue is generally invoiced and collected within 45 days.

The remaining revenue is primarily earned by the Regulated Services Group, which consists of electric, water distribution and wastewater, and natural gas utilities in the United States, Canada, Bermuda and Chile. In this regard, the credit risk related to Regulated Services Group accounts receivable balances of $364,084 is spread over hundreds of thousands of customers. The Company has processes in place to monitor and evaluate this risk on an ongoing basis including background credit checks and security deposits from new customers. In addition, most of the Regulators of the Regulated Services Group allow for a reasonable bad debt expense to be incorporated in the rates and therefore recovered from rate payers.

As of December 31, 2023, the Company’s maximum exposure to credit risk for these financial instruments is as follows: 

	2023
Cash and cash equivalents and restricted cash	$	76,145
Accounts receivable	554,438
Allowance for doubtful accounts	(30,244)
Notes receivable	158,836
	$	759,175

In addition, the Company monitors the creditworthiness of the counterparties to its foreign exchange, interest rate, and energy derivative contracts and assesses each counterparty’s ability to perform on the transactions set forth in the contracts. The counterparties consist primarily of financial institutions. This concentration of counterparties may impact the Company’s overall exposure to credit risk, either positively or negatively, in that the counties may be similarly affected by changes in economic, regulatory or other conditions.

Liquidity risk

Liquidity risk is the risk that the Company will not be able to meet its financial obligations as they fall due. The Company’s approach to managing liquidity risk is to take steps to ensure, to the extent possible, that it will have sufficient liquidity to meet liabilities when due. As of December 31, 2023, in addition to cash on hand of $56,147, the Company has $945,853 available to be drawn on its revolving and term credit facilities. Each of the Company’s revolving credit facilities contain covenants that may limit amounts available to be drawn.

Notes to the Consolidated Financial Statements 143

Algonquin Power & Utilities Corp.

Notes to the Consolidated Financial Statements

December 31, 2023 and 2022

(in thousands of U.S. dollars, except as noted and per share amounts)

24.Financial instruments (continued)

(d)Risk management (continued)

Liquidity risk (continued)

The Company’s liabilities mature as follows: 

	Due less than 1 year		Due 2 to 3 years		Due 4 to 5 years		Due after 5 years		Total
Long-term debt obligations	$	621,856	$	1,333,772	$	2,099,968	$	4,481,961	$	8,537,557
Interest on long-term debt	391,493		602,761		419,950		3,496,032		4,910,236
Purchase obligations	767,287		—		—		—		767,287
Environmental obligation	3,136		22,577		1,820		18,654		46,187
Advances in aid of construction	3,640		—		—		84,495		88,135
Derivative financial instruments:
Cross-currency swap	2,419		4,243		144		9,623		16,429
Interest rate forwards	11,790		—		—		—		11,790
Energy derivative and commodity contracts	14,276		29,273		20,550		12,127		76,226
Contract adjustment payments on Green Equity Units	39,590		—		—		—		39,590
Other obligations	27,796		2,901		2,304		247,480		280,481
Total obligations	$	1,883,283	$	1,995,527	$	2,544,736	$	8,350,372	$	14,773,918

25.Comparative figures

Certain of the comparative figures have been reclassified to conform to the consolidated financial statement presentation adopted in the current year.

Notes to the Consolidated Financial Statements 144