EX-99.3 5 a2023q4-exhibit993xmda.htm EX-99.3 2023 Q4 MD&A
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

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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.

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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.

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The forward-looking information contained herein is subject to risks, uncertainties and other factors that could cause actual results to differ materially from historical results or results anticipated by the forward-looking information. Factors which could cause results or events to differ materially from current expectations include, but are not limited to: changes in general economic, credit, social or market conditions; changes in customer energy usage patterns and energy demand; reductions in the liquidity of energy markets; global climate change; the incurrence of environmental liabilities; natural disasters, diseases, pandemics, public health emergencies and other force majeure events 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.

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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 relat ed to management succession and executive retirement, costs related to prior period adjustments due to changes in tax law, cost s 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

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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 disconti nued 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 investme nts, 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.

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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.

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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 approximat ely 3,140,000 cu stomers). 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 of Arkansas, 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.

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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.

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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 Earnings 1,2 | $115.5 |  | $97.6 |  | 18% |  | $372.0 |  | $420.3 |  | (11)% |  |  |  |  |  |
Adjusted EBITDA 1,3 | $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 share 1,2 | $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.

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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 |

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 Earnings 1 | 115.5 |  |  | 97.6 |
Adjusted EBITDA 1 | 334.3 |  |  | 295.5 |
Adjusted Funds from Operations 1 | 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 Earnings 1 | $ | 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 |

(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 |

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 Earnings 1 | 372.0 |  |  | 420.3 |  |  | 449.0 |  |  |
Adjusted EBITDA 1 | 1,235.4 |  |  | 1,192.8 |  |  | 1,076.3 |  |  |
Adjusted Funds from Operations 1 | 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 Earnings 1 | $ | 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 debt 2 | 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 |

(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 |

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 EBITDA 1 | 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 Concerning Non-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 ended December 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 EBITDA 1 by business units | December 31 |  | December 31
(all dollar amounts in $ millions) | 2023 |  | 2022 |  | 2023 |  | 2022
Divisional Operating Profit for Regulated Services Group 1 | $ | 238.3 |  |  | $ | 214.4 |  |  | $ | 954.1 |  |  | $ | 863.6 |
Divisional Operating Profit for Renewable Energy Group 1 | 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 EBITDA 1 | $ | 334.3 |  |  | $ | 295.5 |  |  | $ | 1,235.4 |  |  | $ | 1,192.8 |
Change in Adjusted EBITDA 1 ($) | $ | 38.8 |  |  |  |  | $ | 42.6 |  |  |
Change in Adjusted EBITDA 1 (%) | 13.1 | % |  |  |  | 3.6 | % |  |

Change in Adjusted EBITDA 1 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 EBITDA 1 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 |

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 Sales 1 | Total Customer Connections 2 |  | Assets | Net Utility Sales 1 | Total Customer Connections 2
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-hr s 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 |

2023 Regulated 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 - electricity 1 | 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 gas 1 | 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 distribution 1 | 94.6 |  |  | 80.4 |  |  | 379.5 |  |  | 346.1 |
Other revenue 2 | 11.6 |  |  | 14.5 |  |  | 51.1 |  |  | 54.2 |
Net Utility Sales 1,3 | 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 |
HLBV 4 | 16.8 |  |  | 2.2 |  |  | 45.3 |  |  | 18.6 |
Divisional Operating Profit 1,5 | $ | 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 conj unction 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 conj unction 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 Profit 1 | $ | 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 Profit 1 | $ | 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 Profit 1 | $ | 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 Profit 1 | $ | 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 |

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 |

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 |

RENEWABLE ENERGY GROUP

2023 Electricity Generation Performance
| Long-Term Average Resource 1 |  | Three months ended December 31 |  | Long-Term Average Resource 1 |  | 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 Lily 2 | 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 Hill 3 | 200.4 |  |  | 144.5 |  |  | 140.2 |  |  | 683.2 |  |  | 501.4 |  |  | 464.2 |
EBR 3 | 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 |
Odell 5 | 238.0 |  |  | 203.2 |  |  | 250.9 |  |  | 831.8 |  |  | 738.7 |  |  | 869.3 |
Deerfield 5 | 167.9 |  |  | 151.3 |  |  | 168.8 |  |  | 546.0 |  |  | 481.3 |  |  | 554.9 |
Sugar Creek 5 | 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 II 6 | 116.0 |  |  | 89.5 |  |  | — |  |  | 281.6 |  |  | 181.1 |  |  | — |
Sandy Ridge II 9 | 75.1 |  |  | 64.7 |  |  | — |  |  | 87.8 |  |  | 70.5 |  |  | — |
Shady Oaks II 10 | 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 |
Dalewood 7 | 0.2 |  |  | 0.1 |  |  | — |  |  | 1.0 |  |  | 0.8 |  |  | — |
Hayhurst New Mexico 11 | 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/A 7 |  | 30.9 |  |  | 29.7 |  |  | N/A 7 |  | 118.0 |  |  | 127.5 |
Sanger | N/A 7 |  | 0.8 |  |  | — |  |  | N/A 7 |  | 11.9 |  |  | 149.1 |
|  |  | 31.7 |  |  | 29.7 |  |  |  |  | 129.9 |  |  | 276.6 |
Total Performance 12 |  |  | 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 1,940.8 GW-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 6,459.0 GW-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
Revenue 1 |  |  |  |  |  |  |
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 - Energy 2 | (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 Credits 5 | 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 income 6 | 32.8 |  |  | 21.6 |  |  | 109.3 |  |  | 91.2 |
HLBV income 7 | 19.3 |  |  | 20.5 |  |  | 71.3 |  |  | 96.4 |
Divisional Operating Profit 3,8,9 | $ | 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 tabl e 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 a n 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 Note 21 in the annual consolidated financial statements, “Segmented Information”. This supplementary disclosure is intended to more fully explain disclosures related to Divisional Operating Profit and provides additional information related to the operating performance of the Renewable Energy Group. Investors are cautioned that Divisional Operating Profit should not be construed as an alternative to revenue.

Algonquin Power & Utilities Corp. - Management Discussion & Analysis | 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 p eriod 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 Profit 1 | $ | 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 Profit 1 | $ | 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 ended December 31, 2023, the Renewable Energy Group’s facilities generated $371.8 million of Divisional Operating Profit as compared to $410.7 million during the sam e 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 Profit 1 | $ | 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 Profit 1 | $ | 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 losses 1 | 13.9 |  |  | 2.1 |  |  | 132.9 |  |  | 21.4 |
Unrealized loss (gain) on energy derivatives included in revenue 2 | 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 value 3 | (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 losses 1 | 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 revenue 2 | 0.5 |  |  | (2.1) |  |  | 7.5 |  |  | 0.9 |
Change in value of investments carried at fair value 3 | (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 Maintenance 1 | 89.4 |  |  | $ | 78.5 |  |  | 347.4 |  |  | 316.5 |
Rate Base Growth | 137.7 |  |  | 253.5 |  |  | 394.6 |  |  | 669.1 |
Property, Plant & Equipment Acquired 2 | — |  |  | — |  |  | — |  |  | 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 Regulate d 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 f rom 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 |

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 obligations 1,2 | $ | 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 obligations 2 | 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 Obligations 3 | $ | 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

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vested portion of the award at that date. During the twelve months ended December 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 ended December 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 ended December 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 ended December 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 ended December 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;

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

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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 elec tion 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 th e 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

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$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,

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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

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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 Earnings 1 | 119.9 |  |  | 56.2 |  |  | 80.5 |  |  | 115.5 |
Adjusted Net Earnings per common share 1 | 0.17 |  |  | 0.08 |  |  | 0.11 |  |  | 0.16 |
Adjusted EBITDA 1 | 341.0 |  |  | 277.7 |  |  | 282.5 |  |  | 334.3 |
Total assets | 17,927.1 |  |  | 17,968.7 |  |  | 17,982.8 |  |  | 18,374.0 |
Long-term debt 2 | 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 Earnings 1 | 140.0 |  |  | 109.6 |  |  | 73.5 |  |  | 97.6 |
Adjusted Net Earnings per common share 1 | 0.20 |  |  | 0.16 |  |  | 0.11 |  |  | 0.14 |
Adjusted EBITDA 1 | 329.3 |  |  | 289.2 |  |  | 276.1 |  |  | 295.5 |
Total assets | 17,669.9 |  |  | 17,737.9 |  |  | 17,653.3 |  |  | 17,627.6 |
Long-term debt 2 | 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.

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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.

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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.

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