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Management Discussion & Analysis

Management of Algonquin Power & Utilities Corp. ("AQN", the "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, 2025. This Management Discussion & Analysis ("MD&A") should be read in conjunction with AQN's audited consolidated financial statements for the years ended December 31, 2025 and 2024. This material is available on SEDAR+ at www.sedarplus.com, on EDGAR at www.sec.gov/edgar and on the AQN website at www.algonquinpower.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			4
Overview and Business Strategy			6
Financial Outlook			9
Significant Updates			10
2025 Fourth Quarter Results From Operations			11
2025 Annual Results From Operations			14



Regulated Services Group			17

Corporate Group Net Earnings and Adjusted Earnings			34
Hydro Group Net Earnings			36

Discontinued Operations: Renewable Energy Group			37
Non-GAAP Financial Measures			38

Summary of Property, Plant and Equipment Expenditures			40
Liquidity and Capital Reserves			41
Share-Based Compensation Plans			43
Enterprise Risk Management			44
Quarterly Financial Information			58

Disclosure Controls and Procedures			59

Critical Accounting Estimates and Policies			59



Algonquin Power & Utilities Corp. - Management Discussion & Analysis			1

Explanatory Notes

Unless otherwise indicated, financial information provided for the years ended December 31, 2025 and 2024 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 6, 2026.

Renewables business sale

On January 8, 2025, the Company completed the previously announced sale of its renewable energy business (excluding hydro) (the "Renewables Sale") to a wholly-owned subsidiary of LS Power ("LS Buyer") for proceeds of approximately $2.1 billion, after subtracting taxes, transaction fees and other preliminary closing adjustments, including an adjustment for estimated remaining completion costs for in-construction assets. Approximately $1.95 billion of such proceeds were received upon the closing of the transaction and an additional approximately $115 million in proceeds were received in 2025 upon monetization of tax attributes on certain in-construction projects. The remaining $35 million of proceeds are currently expected to be received in 2026 upon monetization of tax attributes on additional in-construction projects. Additionally, the Company can receive up to $220 million in cash pursuant to an earn out agreement relating to certain wind assets (the "Earn Out"). The amount and timing of the ultimate net cash proceeds will be dependent on final completion costs for in-construction assets, the associated monetization of tax credits on certain of these projects (including, but not limited to, future events which could cause recapture of part or all of the tax attributes monetized and refund of the associated proceeds), and other final closing adjustments.

During the third quarter of 2024, the Company concluded that the consolidated assets within its former renewable energy group (excluding hydro) met the accounting requirements to be presented as "Held for Sale". As a result, the renewable energy group (excluding hydro) was classified as "discontinued operations" until closing of the Renewables Sale on January 8, 2025. The Company recorded a total impairment loss of $1,357.3 million in 2024 as a result of the classification of the renewable energy group (excluding hydro) as "discontinued operations". Further, the Company recorded loss from discontinued operations of $11.0 million and $37.7 million during the three and twelve months ended December 31, 2025, respectively.

The discontinued operations operated as a distinct segment and had no impact on the operations of the Regulated Services Group operating segment, other than sharing certain corporate support functions and benefiting from corporate debt and equity funding. This MD&A reflects the results of continuing operations, unless otherwise noted.



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

Caution Concerning Forward-Looking Statements and Forward-Looking Information

This document may contain statements that constitute "forward-looking information" within the meaning of applicable securities laws in each of the provinces and territories of Canada and the respective policies, regulations and rules under such laws or "forward-looking statements" within the meaning of the U.S. Private Securities Litigation Reform Act of 1995 (collectively, "forward-looking information"). The words "aims", "anticipates", "believes", "budget", "could", "estimates", "expects", "forecasts", "intends", "may", "might", "plans", "projects", "schedule", "seeks", "should", "strives", "targets", "will", "would", "pursue", "outlook" (and grammatical variations of such terms) and similar expressions are often intended to identify forward-looking information, although not all forward-looking information contains these identifying words. Specific forward-looking information in this document includes, but is not limited to, statements relating to: expected future investments and growth, earnings (including 2026 and 2027 Adjusted Net Earnings per common share) and results of operations; expected tax rates and tax optimization strategies; the timing and costs of gas operational excellence activities; expectations regarding the timing and amount of certain proceeds and the Earn Out in connection with the Renewables Sale; the Company’s integrated customer solution technology platform; future plans and the expected outcomes thereof; 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 dispositions; potential acquisitions, dispositions, projects, initiatives or other transactions; financing plans; expectations regarding future macroeconomic conditions; expectations regarding the Company's corporate development activities and the results thereof; expectations regarding regulatory hearings, motions, orders, settlements, proposals, filings, appeals and approvals, including rate reviews, and the timing, impacts and outcomes thereof; 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; expectations regarding the April 9, 2025 gas incident in Lexington, Missouri, including regulatory actions arising therefrom and availability of insurance coverage; strategy and goals; dividends to shareholders; share price appreciation; credit ratings and equity credit from rating agencies; expectations regarding debt repayment and refinancing; the impact on the Company of actual or proposed laws, regulations and rules; accounting estimates; interest rates, including the anticipated effect of an increase thereof; financing costs; the expected impact of tariffs imposed by the U.S. and Canada and possible changes thereto; 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 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 additional 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 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 dispositions, 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, comply with 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 and operation 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; the absence of any significant indemnification claims arising from the Renewables Sale; the absence of any reputational harm to the Corporation as a result of the Renewables Sale; the absence of adverse reactions or changes in business relationships or relationships with employees following the Renewables Sale; and the ability of the Corporation to realize the anticipated benefits from the Renewables Sale.

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



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

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 impact of existing import controls and tariffs and the imposition of additional 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 operate, 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; 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 dispose of assets (at all or at a competitive price) to fund the Company’s operations and strategic objectives; delays and cost overruns in the design and construction of projects; loss of key customers; a third party joint venture partner acting in a manner contrary to the Corporation’s interests; 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; and the failure to implement the Corporation's strategic objectives or achieve expected benefits relating to acquisitions, dispositions or other initiatives. 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.

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", "Earnings Before Interest and Taxes" ("EBIT"), and "Net Utility Sales", 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. As a pure-play regulated utility, as of the first quarter of 2025, the Company no longer presents "Adjusted Earnings Before Interest, Taxes, Depreciation and Amortization" or "Adjusted Funds from Operations" as these metrics were relevant mainly to the Company's former renewable energy group (excluding hydro) that was sold in connection with the Renewables Sale.

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



Algonquin Power & Utilities Corp. - Management Discussion & Analysis

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.

EBIT

EBIT is a non-GAAP financial measure used by many investors to assess the Company's core operational profitability by measuring the profit generated from day-to-day business activities, excluding interest and tax expenses. AQN uses EBIT to assess its operating performance without the effects of (as applicable): income tax expense or recoveries, interest expense and earnings attributable to non-controlling interests. Earnings attributable to non-controlling interests includes 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 AQN's U.S. wind power and U.S. solar generation facilities). AQN believes that presentation of this measure will enhance an investor's understanding of AQN's operating performance. EBIT 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 EBIT to net earnings attributable to common shareholders, see Non-GAAP Financial Measures starting on page 38 of this MD&A. For reconciliations of EBIT by business segments, see 2025 Fourth Quarter and Annual Regulated Services Group Net Earnings starting on page 20, Corporate Group Net Earnings and Adjusted Net Earnings on page 34 and Hydro Group Net Earnings on page 36.

Adjusted Net Earnings

Adjusted Net Earnings is a non-GAAP financial measure used by many investors to compare net earnings attributable to common shareholders from operations without the effects of certain volatile primarily non-cash items that generally have no current economic impact or items such as acquisition expenses or certain litigation expenses that are viewed as not directly related to a company’s operating performance. AQN uses Adjusted Net Earnings to assess its performance without the effects of (as applicable): gains or losses on foreign exchange, foreign exchange forward contracts, interest rate swaps, acquisition and transition costs, one-time costs of arranging tax equity financing, certain litigation expenses and write down of intangibles and property (including restructuring costs related to the Company's transition to a pure-play utility), 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, prior period adjustments included in the gain (loss) from equity method investments not operated by the Company and other typically non-recurring or unusual items as these are not reflective of the performance of the underlying business of AQN. AQN believes that analysis and presentation of net earnings or loss on this basis will enhance an investor’s understanding of the operating performance of its businesses. Adjusted Net Earnings is not intended to be representative of net earnings or loss determined in accordance with U.S. GAAP, and can be impacted positively or negatively by these items. For a reconciliation of Adjusted Net Earnings to net earnings attributable to common shareholders, see Non-GAAP Financial Measures starting on page 39 and Corporate Group Net Earnings and Adjusted Net Earnings on page 34 of this MD&A.

The composition of Adjusted Net Earnings has been changed from that previously disclosed in the Company's most-recently filed quarterly interim MD&A to exclude dividends on the Company's Series A and Series D preferred shares. Management believes this change better aligns the measure with industry practice and improves the metric's usefulness to investors. Comparative figures for this metric have been adjusted for the new composition.

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 2025 Fourth Quarter and Annual Regulated Services Group Net Earnings on page 20 of this MD&A.



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

Overview and Business Strategy

AQN is incorporated under the Canada Business Corporations Act. The Company's operations are organized across two business units consisting of (i) the Regulated Services Group, which primarily owns and operates a portfolio of regulated electric, water distribution and wastewater systems and natural gas utility systems and transmission operations in the United States, Canada, Bermuda and Chile; and (ii) the Hydro Group, which consists of hydroelectric generation facilities located in Canada that were not sold as part of the Renewables Sale. Additionally, the Company has a corporate function, the Corporate Group, consisting of corporate debt and corporate and shared services that primarily support the Regulated Services Group and the Hydro Group. The Company's investment in Atlantica Sustainable Infrastructure plc ("Atlantica"), which previously formed part of the Corporate Group, was sold during the fourth quarter of 2024. The Company’s former renewable energy group (excluding hydro) is reported as discontinued operations (see Note 23 to the audited consolidated financial statements - Disposition of Renewable Energy Business) and was sold by the Company on January 8, 2025. The Company's business units align with how the Company assesses financial performance and makes decisions regarding resource allocations. 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 investment grade credit ratings.

Summary Structure of the Business

The following chart depicts, in summary form, AQN's key operating business units. A more detailed description of AQN's organizational structure as of the date of the AIF can be found in the most recent AIF.



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

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 1,272,000 customer connections as at December 31, 2025 (using an average of 2.5 customers per connection, this translates into approximately 3,170,000 customers). The Regulated Services Group seeks to provide safe, high quality, and reliable services to its customers and to deliver stable and predictable earnings to AQN. The Regulated Services Group seeks to deliver long-term growth within its service territories, including through the pursuit of capital investment opportunities and other initiatives.

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 311,000 electric customer connections as at December 31, 2025. 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 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 583,000 customer connections as at December 31, 2025.

The Regulated Services Group's regulated natural gas distribution utility systems are located in the U.S. States of Georgia, Illinois, Iowa, Massachusetts, Missouri New Hampshire, and New York, and in the Canadian Province of New Brunswick, which together served approximately 378,000 natural gas customer connections as at December 31, 2025.

Below is a breakdown of the Regulated Services Group's Revenue by geographic area and by commodity for the twelve months ended December 31, 2025.



Algonquin Power & Utilities Corp. - Management Discussion & Analysis

Hydro Group

The Hydro Group is comprised of 14 hydroelectric generating facilities located in the Canadian provinces of Alberta, Ontario, New Brunswick and Quebec with a combined gross generating capacity of approximately 112 MW and a net generating capacity of approximately 104 MW.

Corporate Group

The Corporate Group primarily consists of AQN’s corporate and shared services and corporate debt, in addition to certain ancillary investments. Prior to the sale of the Company's investment in Atlantica on December 12, 2024, the Corporate Group also included the Company’s interest in Atlantica.

The Company’s former renewable energy group (excluding hydro) is reported as "discontinued operations" and was sold by the Company on January 8, 2025.



Algonquin Power & Utilities Corp. - Management Discussion & Analysis

Financial Outlook

The following discussion should be read in conjunction with the Caution Concerning Forward-Looking Statements and Forward-Looking Information section in this MD&A. Actual results may differ materially from the estimates below. Accordingly, investors are cautioned not to place undue reliance on these estimates.

The Company estimates that its Adjusted Net Earnings per common share will be within a range of $0.35 - $0.37 for 2026 (see Caution Concerning Non-GAAP Measures). With respect to the Company's previously disclosed Adjusted Net Earnings per common share outlook for 2027, the Company now expects its effective tax rate in 2027 to be in the mid-to-high twenties as compared to the previously anticipated low-to-mid twenties estimate, resulting in a decrease to anticipated 2027 Adjusted Net Earnings per common share of slightly more than $0.03 compared to the Company's previous estimate. The Company also now expects the timing of gas operational excellence activities to extend into 2027. When combined, these factors result in an updated expected Adjusted Net Earnings per common share range of $0.38 - $0.42 for 2027. The Company continues to evaluate various tax strategies to optimize its effective tax rate but expects the majority of the benefits from such strategies to be realized after 2027. The Company also expects the costs of gas operational excellence activities assumed in 2027 to normalize thereafter.

The Company is focused on organic capital investment, with utility capital expenditures of approximately $3.2 billion expected for 2026 through 2028 including approximately $0.8 billion in 2026.

The foregoing financial outlook, including estimated Adjusted Net Earnings per common share and expectations regarding capital expenditures, is based on the following key assumptions, as well as those set out under Caution Concerning Forward-Looking Statements and Forward-Looking Information:

•resolution of customer billing matters, regulatory investigations and rate decisions in line with expectations, including absence of material write downs of assets;

•normalized weather patterns in the geographical areas in which the Company operates;

•insurance coverage remains effective and sufficient;

•capital projects being completed on time, substantially in line with budgeted costs, and without adverse tariff impacts;

•timely receipt of required regulatory approvals and permits;

•the absence of material disruptions to supply chains or labour availability affecting pricing, operations or project execution;

•realization of company-wide efficiency initiatives in line with expectations;

•the absence of significant changes in applicable political or macroeconomic environments or capital markets, including with respect to legislation, interest rates or inflation;

•a Canadian dollar/U.S. dollar exchange rate and a Chilean peso/U.S. dollar exchange rate in line with expectations;

•receipt of anticipated proceeds under the Earn Out;

•a low twenties percentage effective tax rate in 2026, and a mid-to-high twenties percentage effective tax rate in 2027;

•the timing and amount of gas operational excellence activities costs in line with expectations;

•energy production consistent with long-term averages and realized pricing in line with expectations;

•the absence of significant adverse litigation outcomes, fines, penalties, losses and inverse condemnation rulings; and

•access to capital markets at pricing consistent with current market levels.



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

Significant Updates

Operating Results

AQN's operating results relative to the same period last year are as follows:


	Three months ended December 31						Twelve months ended December 31
(all dollar amounts in $ millions except per share information)	2025		2024		Change		2025		2024		Change
Net earnings (loss) attributable to shareholders from continuing operations	$	32.0	$	(107.5)	130	%	$	218.5	$	65.3	235	%
Net earnings (loss) attributable to common shareholders from continuing operations	29.4		(110.2)		127	%	208.0		54.8		280	%
Net earnings (loss) attributable to common shareholders from continuing operations and discontinued operations	18.4		(189.1)		110	%	170.3		(1,391.0)		112	%


Adjusted Net Earnings1	47.2		42.5		11	%	258.8		221.6		17	%
EBIT1	93.2		115.8		(20)	%	493.5		540.8		(9)	%
Net earnings (loss) per common share from continuing operations	$	0.04	$	(0.14)	129	%	$	0.27	$	0.07	286	%
Net earnings per common share from continuing operations and discontinued operations	$	0.02	$	(0.25)	108	%	$	0.22	$	(1.90)	112	%
Adjusted Net Earnings per common share1	$	0.06	$	0.06	—	%	$	0.34	$	0.30	13	%
1 See Caution Concerning Non-GAAP Measures.

Management Changes

On February 16, 2026, the Company appointed Kristin von Fischer as Chief Human Resources Officer, effective as of such date.

On January 5, 2026, the Company announced the appointment of Peter Norgeot as Chief Operating Officer, effective as of such date.

On November 7, 2025, the Company announced the appointment of Robert Stefani as Chief Financial Officer. Mr. Stefani's appointment was effective January 5, 2026. Brian Chin acted as Interim Chief Financial Officer until January 5, 2026 and after such date, has continued with the Company in his Vice President, Investor Relations role.

On June 18, 2025, the Company announced the appointment of Amy Walt as Chief Customer Officer, effective June 30, 2025.

On June 9, 2025, the Company announced the appointment of Noel Black as Chief Regulatory and External Affairs Officer, effective June 30, 2025.

On January 31, 2025, the Company announced that Roderick West would join the Company as Chief Executive Officer. Mr. West’s appointment as Chief Executive Officer was effective as of 12:00 p.m. (Eastern time) on March 7, 2025. Chris Huskilson stepped down as Chief Executive Officer as of such date and continued in his role as a director of the Company until November 24, 2025.

Sale of Renewable Energy Business

On January 8, 2025, the Company completed the sale of its renewable energy business (excluding hydro) to LS Buyer. Please refer to the section titled “Explanatory Notes” above for additional details regarding the Renewables Sale.



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

2025 Fourth Quarter Results From Operations


Key Financial Information1	Three months ended December 31
(all dollar amounts in $ millions except per share information)	2025		2024
Revenue	$	630.7	$	584.8
Net revenue	446.8		432.6
Net earnings (loss) attributable to shareholders	32.0		(107.5)
Net earnings (loss) attributable to common shareholders	29.4		(110.2)

Net earnings (loss) attributable to common shareholders from continuing operations and discontinued operations	18.4		(189.1)
Adjusted Net Earnings2	47.2		42.5
Dividends declared to common shareholders	50.5		50.4
Weighted average number of common shares outstanding	768,429,981		767,465,543
Per common share
Basic and diluted net earnings (loss)	$	0.04	$	(0.14)
Basic and diluted net earnings from continuing operations and discontinued operations	$	0.02	$	(0.25)
Basic and diluted net loss from discontinued operations	$	(0.01)	$	(0.10)
Adjusted Net Earnings2	$	0.06	$	0.06
Dividends declared to common shareholders	$	0.07	$	0.07


1			Reflects results of continuing operations unless marked otherwise (see Explanatory Notes).
2			See Caution Concerning Non-GAAP Measures.

For the three months ended December 31, 2025, AQN reported revenue of $630.7 million as compared to $584.8 million in the comparative period, an increase of $45.9 million. This increase was mainly driven by higher pass through commodity costs across all gas systems, as well as the implementation of approved rates of $10.3 million.

The following table outlines the changes to Adjusted Net Earnings1 for the three months ended December 31, 2025 as compared to the same period in 2024, including the breakdown of net earnings attributable to common shareholders by the Company's main business units and the discussion below outlines the changes to net earnings attributable to common shareholders:


Net Earnings by business units2 and Total Adjusted Net Earnings1	Three months ended December 31
(all dollar amounts in $ millions)	2025		2024		Change
Net earnings for Regulated Services Group	$	73.6	$	60.5	$	13.1
Net earnings for Hydro Group	2.1		2.5		$	(0.4)
Net loss for Corporate Group	(46.3)		(173.2)		$	126.9
Total Net Earnings (Loss)	29.4		(110.2)		139.6
Add: Adjusted items	17.8		152.7		(134.9)
Total Adjusted Net Earnings1	$	47.2	$	42.5	$	4.7


1			See Caution Concerning Non-GAAP Measures.
2			Reflects results of continuing operations unless marked otherwise (see Explanatory Notes).



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


Change in Net Earnings and Adjusted Net Earnings1 Breakdown2	Three months ended December 31, 2025
(all dollar amounts in $ millions)	Regulated Services		Hydro		Corporate		Total
Change in Net Earnings attributable to common shareholders
Net earnings (loss) attributable to common shareholders - Prior period balances	$	60.5	$	2.5	$	(173.2)	$	(110.2)

EBIT1,3
Electricity	(4.7)		—		—		(4.7)
Natural Gas	6.4		—		—		6.4
Water	(1.0)		—		—		(1.0)
Other	(1.6)		(0.3)		(21.4)		(23.3)
Total change in EBIT1	(0.9)		(0.3)		(21.4)		(22.6)

Interest expense	10.6		—		7.3		17.9
Income tax expense	1.4		—		140.9		142.3
Net effect of non-controlling interests	2.0		(0.1)		—		1.9
Series A Shares and Series D Shares dividend	—		—		0.1		0.1
Total change in net earnings (loss)	13.1		(0.4)		126.9		139.6

Net earnings (loss) attributable to common shareholders - Current period balances	73.6		2.1		(46.3)		29.4

Change in Adjusted Net Earnings1
Adjusted Net Earnings (Loss)1 - Prior period balance3	60.5		2.5		(20.5)		42.5
Total change in net earnings (loss)	13.1		(0.4)		126.9		139.6
Total change in adjusted items,3	—		—		(134.9)		(134.9)
Adjusted Net Earnings (loss)1 - Current period balances	$	73.6	$	2.1	$	(28.5)	$	47.2


1			See Caution Concerning Non-GAAP Measures.
2			Reflects results of continuing operations unless marked otherwise (see Explanatory Notes).
3			See Corporate Group Net Earnings and Adjusted Net Earnings.

For the three months ended December 31, 2025, AQN reported net earnings attributable to common shareholders of $29.4 million and basic net earnings per common share of $0.04. During the comparative period in 2024, the Company reported net loss attributable to common shareholders of $110.2 million and basic net loss per common share of $0.14. The net earnings attributable to common shareholders increased by $139.6 million and the basic net earnings per common share increased by $0.18. These increases were primarily driven by:

•an increase of $13.1 million in the net earnings of the Regulated Services Group primarily due to:

–an increase in net earnings of $26.3 million primarily driven by the implementation of approved rates of $10.3 million, an increase in net earnings of $5.4 million due to favorable weather normalization, lower interest expense of $10.6 million as a result of the repayment of debt with the proceeds from the Renewables Sale and the proceeds from the sale of the Company’s investment in Atlantica; partially offset by;

–a decrease of $13.2 million primarily driven by higher operating expenses of $2.4 million (unfavorable operating expenses such as a targeted relief initiative for customers of $8.5 million agreed to as part of the Empire District Electric System (MO) rate case settlement and a non-recoverable write-off of $2.0 million pertaining to the Lexington gas incident; partially offset by favorable labour and maintenance expenses), higher depreciation expense of $3.7 million due to additional assets placed in service, and other non-recurring expenses primarily due to a $7.3 million write-off related to the discontinuation of a solar project at the CalPeco Electric System; and



Algonquin Power & Utilities Corp. - Management Discussion & Analysis

•an increase of $126.9 million in the net earnings of the Corporate Group primarily due to:

–an increase in net earnings of $148.2 million primarily driven by a decrease in income tax expenses of $140.9 million due to valuation allowance recorded in 2024 on Canadian deferred tax assets and the effect from the restructuring of certain intercompany financing arrangements which were executed in advance of the implementation of global minimum tax rules in the various jurisdictions in which the Company operates, as well as a $7.3 million decrease in interest expense as a result of the repayment of debt with the proceeds of the Renewables Sale and the proceeds from the sale of the Company's investment in Atlantica; partially offset by;

–a decrease of $24.9 million primarily driven by a decrease of $10.9 million owing to decreased dividends received from the Company’s investment in Atlantica during the fourth quarter of 2024, which was sold in the fourth quarter of 2024, as well as a $14.0 million increase in non-recurring charges primarily due to restructuring.

For the three months ended December 31, 2025 and December 31, 2024, AQN reported Adjusted Net Earnings per common share of $0.06 (see Caution Concerning Non-GAAP Measures). Adjusted Net Earnings increased by $4.6 million period over period (see Caution Concerning Non-GAAP Measures). This increase was primarily driven by the factors noted above (see Reconciliation of Adjusted Net Earnings to Net Earnings).

For the three months ended December 31, 2025, cash provided by operating activities increased by $127.9 million as compared to the same period in 2024, primarily as a result of an increase in Net Earnings of $139.6 million and changes in working capital items of $157.7 million (see Note 21 to the audited consolidated financial statements - Non Cash Operating Items). For the three months ended December 31, 2025 cash provided by investing activities decreased by $1,005.0 million as a result of non-recurring proceeds from the sale of the Company's investment in Atlantica in the prior year. For the three months ended December 31, 2025 cash provided by financing activities increased by $890.4 million primarily because in the fourth quarter of the 2024, the Company repaid debt using the proceeds from the sale of the investment in Atlantica.



Algonquin Power & Utilities Corp. - Management Discussion & Analysis

2025 Annual Results From Operations1


Key Financial Information	Twelve months ended December 31
(all dollar amounts in $ millions except per share information)	2025		2024		2023
Revenue	$	2,433.6	$	2,319.5	$	2,403.9
Net Revenue	1,793.8		1,718.7		1,686.9
Net earnings (loss) attributable to shareholders	218.5		65.3		(14.4)
Net earnings attributable to common shareholders	208.0		54.8		(22.8)

Net earnings (loss) attributable to common shareholders from continuing operations and discontinued operations	170.3		(1,391.0)		20.3


Adjusted Net Earnings2	258.8		221.6		271.0
Dividends declared to common shareholders	201.8		260.0		301.8
Weighted average number of common shares outstanding	768,098,435		731,721,239		688,738,717
Per common share
Basic and diluted net earnings (loss)	$	0.27	$	0.07	$	(0.03)
Basic and diluted net earnings (loss) from continuing operations and discontinued operations	$	0.22	$	(1.90)	0.03

Adjusted Net Earnings2	$	0.34	$	0.30	$	0.39
Dividends declared to common shareholders	$	0.26	$	0.35	$	0.43

Total assets - Continuing and discontinued operations	14,136.2		16,961.7		18,374.0
Long-term debt - Continuing and discontinued operations	6,532.9		8,047.5		8,516.0




1			Reflects results of continuing operations unless marked otherwise (see Explanatory Notes).
2			See Caution Concerning Non-GAAP Measures.

For the twelve months ended December 31, 2025, AQN reported revenue of $2,433.6 million as compared to $2,319.5 million in the comparative period, an increase of $114.1 million. This increase was mainly driven by the implementation of approved rates of $41.6 million, favourable weather which resulted in an increase in revenue of approximately $13.9 million at the Empire Electric System, as well as higher pass-through costs driven by increased commodity prices.

The following table outlines the changes to Adjusted Net Earnings1 for the twelve months ended December 31, 2025 as compared to the same period in 2024, including the breakdown of net earnings attributable to common shareholder by the Company's main business units, and the discussion below outlines the changes to net earnings attributable to common shareholders:


Net Earnings and Adjusted Net Earnings1 by business unit2	Twelve months ended December 31
(all dollar amounts in $ millions)	2025		2024		Change
Net earnings for Regulated Services Group	$	351.0	$	260.1	$	90.9
Net earnings for Hydro Group	31.1		12.0		19.1
Net loss for Corporate Group	(174.1)		(217.3)		43.2
Total Net Earnings	208.0		54.8		153.2
Add: Adjusted items	50.8		166.8		(116.0)
Total Adjusted Net Earnings1	$	258.8	$	221.6	$	37.2



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


Change in Net Earnings and Adjusted Net Earnings1 Breakdown2	Twelve months ended December 31, 2025
(all dollar amounts in $ millions)	Regulated Services		Hydro		Corporate		Total
Change in Net Earnings attributable to common shareholders
Net earnings (loss) attributable to common shareholders- Prior period balances	$	260.1	$	12.0	$	(217.3)	$	54.8
EBIT1
Electricity	14.4		—		—		14.4
Natural Gas	35.9		—		—		35.9
Water	11.8		—		—		11.8
Other	9.2		(0.2)		(118.4)		(109.4)
Total change in EBIT1	71.3		(0.2)		(118.4)		(47.3)

Interest expense	50.4		—		30.7		81.1
Income tax expense	(29.2)		20.1		130.9		121.8
Net effect of non-controlling interests	(1.6)		(0.8)		—		(2.4)
Total change in net earnings	90.9		19.1		43.2		153.2

Net earnings (loss) attributable to common shareholders - Current period balances	351.0		31.1		(174.1)		208.0

Change in Adjusted Net Earnings1
Adjusted Net Earnings (Loss)1 - Prior period balance3	260.1		12.0		(50.5)		221.6
Total change in net earnings	90.9		19.1		43.2		153.2
Total change in adjusted items3	—		—		(116.0)		(116.0)
Adjusted Net Earnings (loss)1 - Current period balances	$	351.0	$	31.1	$	(123.3)	$	258.8




1			See Caution Concerning Non-GAAP Measures.
2			Reflects results of continuing operations unless marked otherwise (see Explanatory Notes).
3			See Corporate Group Net Earnings and Adjusted Net Earnings.

For the twelve months ended December 31, 2025, AQN reported net earnings attributable to common shareholders of $208.0 million and basic net earnings per common share of $0.27. During the comparative period in 2024, the Company reported net earnings attributable to common shareholders of $54.8 million and basic net earnings per common share of $0.07. The net earnings attributable to common shareholders increased by $153.2 million, and basic net earnings per common share increase by $0.20. The increases were primarily driven by:

•an increase of $90.9 million in the net earnings of the Regulated Services Group, primarily due to:

–an increase in net earnings of $105.9 million primarily due to the implementation of approved rates of $41.6 million, favourable weather normalization, which resulted in an increase in net earnings of $13.9 million, and lower interest expense of $50.4 million as a result of the repayment of debt with the proceeds from the Renewables Sale and the proceeds from the sale of the Company’s investment in Atlantica; partially offset by;

–a decrease in net earnings of $14.8 million primarily due to higher depreciation of $5.3 million due to higher organic depreciation, net of $11.9 million due to depreciation deferral adjustments related to the Granite State Electric and EnergyNorth Gas Systems, lower net operating expenses of $2.2 million due to lower labour and maintenance expenses across all systems, partially offset by a targeted relief initiative for customers of $8.5 million agreed to as part of the Empire District Electric System (MO) rate case settlement, and a write-off of $7.3 million related to the discontinuation of a solar project at the CalPeco Electric System.

•an increase of $19.1 million in the net earnings of the Hydro Group primarily due to a tax recovery; and

•an increase in the net earnings of the Corporate Group of $43.2 million, primarily due to:



Algonquin Power & Utilities Corp. - Management Discussion & Analysis

–an increase in net earnings of $161.6 million primarily due to a decrease in income tax expense of $130.9 million primarily driven by valuation allowance recorded in 2024 on Canadian deferred tax assets and the effect from the restructuring of certain intercompany financing arrangements which were executed in advance of the implementation of global minimum tax rules in the various jurisdictions in which the Company operates, as well as a $30.7 million decrease in interest expense as a result of the repayment of debt with the proceeds of the Renewables Sale and the proceeds from the sale of the Company's investment in Atlantica; partially offset by;

–a decrease in net earnings of $97.7 million primarily driven by a $21.4 million fair value mark to market gain recorded in 2024, a decrease of $76.3 million owing to decreased dividends received from the Company’s investment in Atlantica, which was sold in the fourth quarter of 2024, and an increase of $18.4 million in foreign exchange losses due to fluctuations in USD-CAD exchange rates.

•The above increases were offset by common share dilution upon the issuance of 77,293,314 common shares in the second quarter of 2024, which issuance was almost entirely due to common shares that were issued in connection with the settlement of the purchase contracts that were a component of the Company's equity units.

For the twelve months ended December 31, 2025, AQN reported Adjusted Net Earnings per common share of $0.34 as compared to $0.30 per common share during the same period in 2024, an increase of $0.04 (see Caution Concerning Non-GAAP Measures). Adjusted Net Earnings per common share exceeded the top end of Company’s previously provided guidance range by $0.02. This was driven by accelerated realization of operating expense savings, lower depreciation expense resulting from authorized deferrals, and tax adjustments. These benefits were partially offset by costs associated with a targeted relief initiative for customers agreed to as part of the Empire District Electric System (MO) settlement as well as costs associated with the discontinuation of a solar project at the CalPeco Electric System. Adjusted Net Earnings increased by $37.2 million year over year (see Caution Concerning Non-GAAP Measures). This increase was primarily driven by the factors noted above, excluding the impact of the $21.4 million fair value mark to market gain (See Reconciliation of Adjusted Net Earnings to Net Earnings).

For the twelve months ended December 31, 2025, cash provided by operating activities increased by $111.9 million as compared to the same period in 2024, primarily due to changes in working capital items of $93.8 million (See Note 16 to the audited consolidated financial statements - Non Cash Operating Items); partially offset by an increase in net earnings. Cash flow provided by investing activities increased by $1,030.6 million mainly due to proceeds received from the Renewables Sale and the sale of the Company's investment in Atlantica. These proceeds were used for the repayment of debt, which was the primary factor leading to an increase of $1,254.8 million in the cash flow used in financing activities.



Algonquin Power & Utilities Corp. - Management Discussion & Analysis

REGULATED SERVICES GROUP

The Regulated Services Group primarily operates rate-regulated utilities that as of December 31, 2025 provided electric generation and transmission services as well as distribution services in the electric, natural gas and water and wastewater sectors to approximately 1,272,000 customer connections, which is an increase of approximately 7,000 customer connections as compared to December 31, 2024.

The Regulated Services Group seeks to deliver long-term growth within its service territories, including through the pursuit of capital investment opportunities and other initiatives.


Utility System Type	As at December 31
	2025					2024
(all dollar amounts in $ millions)	Assets		Net Utility Sales1		Total Customer Connections2	Assets		Net Utility Sales1		Total Customer Connections2
Electricity	5,566.5		934.9		311,000	5,454.5		910.4		310,000
Natural Gas	2,018.1		387.4		378,000	1,921.4		363.2		378,000
Water and Wastewater	1,895.4		400.0		583,000	1,786.3		378.0		577,000
Other	98.6		32.3			122.2		30.5
Other revenue			60.7					54.0
Less: Cost of Sales			(28.4)					(23.5)
Total	$	9,578.6	$	1,754.6	1,272,000	$	9,284.4	$	1,682.1	1,265,000

Accumulated Deferred Income Taxes Liability	$	929.4				$	833.6


1			Net Utility Sales for the twelve months ended December 31, 2025 and 2024. 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, generation and transmission systems are comprised of regulated electrical distribution utility systems that served approximately 311,000 customer connections in the U.S. States of Arkansas, California, Kansas, Missouri, New Hampshire and Oklahoma, as well as in Bermuda as at December 31, 2025.

The natural gas distribution systems are comprised of regulated natural gas distribution utility systems that served approximately 378,000 customer connections located in the U.S. States of Georgia, Illinois, Iowa, Massachusetts, Missouri, New Hampshire and New York, and in the Canadian Province of New Brunswick as at December 31, 2025.

The water and wastewater distribution systems are comprised of regulated water distribution and wastewater utility systems that served approximately 583,000 customer connections located in the U.S. States of Arizona, Arkansas, California, Illinois, Missouri, New York, and Texas, as well as in Chile, as at December 31, 2025.



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

2025 Fourth Quarter and Annual Usage Results


Electric Distribution Systems	Three months ended December 31		Twelve months ended December 31
	2025	2024	2025	2024
Average Active Electric Customer Connections For The Period
Residential	263,500	263,300	263,400	263,400
Commercial and industrial	43,500	43,200	43,400	43,000
Total Average Active Electric Customer Connections For The Period	307,000	306,500	306,800	306,400

Customer Usage (GW-hrs)
Residential	653.3	583.3	2,858.2	2,777.5
Commercial and industrial	922.9	954.6	3,856.2	3,866.7
Total Customer Usage (GW-hrs)	1,576.2	1,537.9	6,714.4	6,644.2

For the three months ended December 31, 2025, the electric distribution systems' usage totaled 1,576.2 GW-hrs as compared to 1,537.9 GW-hrs for the same period in 2024, an increase of 38.3 GW-hrs or 2.5%. The increase in electricity consumption is primarily due to favourable weather at the Empire District Electric System.

For the twelve months ended December 31, 2025, the electric distribution systems' usage totaled 6,714.4 GW-hrs as compared to 6,644.2 GW-hrs for the same period in 2024, an increase of 70.2 GW-hrs or 1.1%. The increase in electricity consumption is primarily due to favourable weather and customer growth at the Empire District Electric System.


Natural Gas Distribution Systems	Three months ended December 31		Twelve months ended December 31
	2025	2024	2025	2024
Average Active Natural Gas Customer Connections For The Period
Residential	322,100	322,700	322,700	323,000
Commercial and industrial	40,300	40,300	40,300	40,000
Total Average Active Natural Gas Customer Connections For The Period	362,400	363,000	363,000	363,000

Customer Usage (MMBTU)
Residential	5,182,000	4,941,000	20,789,000	19,770,000
Commercial and industrial	6,864,000	5,114,000	22,799,000	20,301,000
Total Customer Usage (MMBTU)	12,046,000	10,055,000	43,588,000	40,071,000

For the three months ended December 31, 2025, usage at the natural gas distribution systems totaled 12,046,000 MMBTU as compared to 10,055,000 MMBTU during the same period in 2024, an increase of 1,991,000 MMBTU, or 19.8%. The increase is primarily due to favourable weather at all distributions systems.

For the twelve months ended December 31, 2025, usage at the natural gas distribution systems totaled 43,588,000 MMBTU as compared to 40,071,000 MMBTU during the same period in 2024, an increase of 3,517,000 MMBTU, or 8.8%. The increase is primarily due to favourable weather at all distributions systems.



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


Water and Wastewater Distribution Systems	Three months ended December 31		Twelve months ended December 31
	2025	2024	2025	2024
Average Active Customer Connections For The Period
Water distribution customer connections	519,200	513,300	516,700	510,600
Wastewater customer connections	55,700	55,600	55,800	55,700
Total Average Active Customer Connections For The Period	574,900	568,900	572,500	566,300

Gallons Provided (millions of gallons)
Water provided	9,747	10,204	41,153	39,747
Wastewater treated	927	963	3,694	3,716
Total Gallons Provided (millions of gallons)	10,674	11,167	44,847	43,463

For the three months ended December 31, 2025, the water and wastewater distribution systems provided approximately 9,747 million gallons of water to customers and treated approximately 927 million gallons of wastewater. This is compared to 10,204 million gallons of water provided and 963 million gallons of wastewater treated during the same period in 2024, a decrease in total gallons provided of 457 million or 4.5% and a decrease in total gallons treated of 36 million or 3.7%. The decrease in water is primarily due lower usage at the Park Water and Litchfield Park Water Systems.

For the twelve months ended December 31, 2025, the water and wastewater distribution systems provided approximately 41,153 million gallons of water to customers and treated approximately 3,694 million gallons of wastewater. This is compared to 39,747 million gallons of water provided and 3,716 million gallons of wastewater treated during the same period in 2024, an increase in total gallons provided of 1,406 million or 3.5% and decrease in total gallons treated of 22 million or 0.6%. The increase in water is primarily due to favourable weather at the New York Water System.



Algonquin Power & Utilities Corp. - Management Discussion & Analysis

2025 Fourth Quarter and Annual Regulated Services Group Net Earnings


	Three months ended				Twelve months ended
	December 31				December 31
(all dollar amounts in $ millions)	2025		2024		2025		2024
Revenue
Regulated electricity distribution	$	309.5	$	304.6	$	1,292.7	$	1,276.1
Less: Regulated electricity purchased	(87.2)		(85.1)		(357.8)		(365.7)
Net Utility Sales – electricity1	222.3		219.5		934.9		910.4
Regulated gas distribution	191.1		152.5		614.4		546.4
Less: Regulated gas purchased	(82.1)		(51.1)		(227.0)		(183.2)
Net Utility Sales – natural gas1	109.0		101.4		387.4		363.2
Regulated water reclamation and distribution	103.0		104.0		426.6		406.1
Less: Regulated water purchased	(6.2)		(8.4)		(26.6)		(28.1)
Net Utility Sales – water reclamation and distribution1	96.8		95.6		400.0		378.0

Other revenue2	17.8		15.8		60.7		54.0
Less: Other Cost of Sales	(8.4)		(7.6)		(28.4)		(23.5)
Net Utility Sales1,3	437.5		424.7		1,754.6		1,682.1
Operating expenses	224.1		221.7		853.9		855.2
Depreciation and amortization	101.3		97.6		392.1		386.8
Interest, dividend and other income	7.4		10.1		28.8		33.4
Other expenses
Pension and post-employment non-service costs	$	(1.9)	$	(3.7)	(3.7)		$	(14.1)
Other net losses	$	(16.3)	$	(10.3)	(30.4)		$	(17.8)
Gain/(Loss) on derivative financial instruments	$	(0.3)	$	0.4	8.9		$	(0.7)
EBIT1,4	$	101.0	$	101.9	$	512.2	$	440.9
Interest expense	(36.0)		(46.6)		(141.4)		(191.8)
Income tax expense	$	(13.9)	$	(15.3)	(96.2)		(67.0)
Net effect of non-controlling interests6	$	22.5	$	20.5	76.4		78.0
Net Earnings	$	73.6	$	60.5	$	351.0	$	260.1


1			See Caution Concerning Non-GAAP Measures.
2			See Note 19 in the audited consolidated financial statements.
3			This table contains a reconciliation of Net Utility Sales to revenue for the Regulated Services Group. The relevant sections of the table are derived from and should be read in conjunction with the audited consolidated statement of operations and Note 19 in the audited 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			This table contains a reconciliation of EBIT to net earnings for the Regulated Services Group. The relevant sections of the table are derived from and should be read in conjunction with the audited consolidated statement of operations and Note 19 in the audited consolidated financial statements, "Segmented Information". This supplementary disclosure is intended to more fully explain disclosures related to EBIT and provides additional information related to the operating performance of the Regulated Services Group. Investors are cautioned that EBIT should not be construed as an alternative to net earnings.
6			Net effect of non-controlling interests primarily includes HLBV income from Empire Electric.



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

2025 Fourth Quarter Regulated Services Group Operating Results

For the three months ended December 31, 2025, the Regulated Services Group reported revenue of $603.6 million (comprised of $309.5 million of regulated electricity distribution, $191.1 million of regulated gas distribution and $103.0 million of regulated water reclamation and distribution) as compared to revenue of $561.1 million in the comparable period in the prior year (comprised of $304.6 million of regulated electricity distribution, $152.5 million of regulated gas distribution and $104.0 million of regulated water reclamation and distribution).

For the three months ended December 31, 2025, the Regulated Services Group reported net earnings of $73.6 million as compared to $60.5 million for the comparable period in the prior year.

Highlights of the changes are summarized in the following table:


(all dollar amounts in $ millions)	Three months ended December 31
Prior Period Net Earnings	$	60.5

Regulated Services Group EBIT1:
Electricity: Decrease is primarily due to: –favourable weather, which resulted in an increase to net earnings of approximately $5.4 million –lower operating expenses of approximately $9.7 million, including a $4.0 million favourable impact from an adjustment recorded in 2024 (benefiting the fourth quarter of 2024), with the remaining decrease driven by lower labour and maintenance expenses More than offset by: –additional expense of $8.5 million in respect of a targeted relief initiative for customers of agreed to as part of the Empire District Electric System (MO) rate case settlement –unrecoverable fuel costs of approximately $2.3 million at the Empire District Electric System –a write-off of $7.3 million related to the discontinuation of a solar project at the CalPeco Electric System	(4.7)
Gas: Increase is primarily due to: –the implementation of approved rates of $4.0 million at Midstates (MO) and Peach State (GA) Gas Systems –higher net revenue of approximately $2.0 million due to billing cycle changes at the Midstates (MO) Gas System –net items totaling $4.8 million recorded in the fourth quarter of 2024, primarily related to the EnergyNorth (NH) and Empire District (MO) Gas Systems. Partially offset by: –items totaling $3.5 million, consisting of a $1.0 million fuel inventory write-off at the Midstates (MO) Gas System and $2.5 million of operating expenses associated with the Lexington gas incident	6.4
Water: Decrease is primarily due to: –the implementation of approved rates of $4.2 million at the New York (NY), Missouri Water (MO), Bella Vista (AZ), Beardsley (AZ), Cordes Lake (AZ) Water System and Rio Rico (AZ) Water and Sewer System More than offset by: –higher depreciation expense of $3.2 million due to organic growth –lower revenue at the New York (NY) Water system of approximately $1.0 million related to timing	(1.0)
Other: decrease primarily due to non-recurring expenses	(1.6)
Interest expense: Decrease primarily due to the repayment of debt with the proceeds of the Renewables Sale and the sale of the Company's investment in Atlantica which were partially pushed down into the Regulated Services Group	10.6
Income tax expense: Lower income tax expense primarily due to tax adjustment recorded during the quarter as a result of the enacted Tax Credits Act 2025 in Bermuda	1.4
Net effect of non-controlling interests: Increase due to higher wind production resulting in higher HLBV	2.0
Current Period Net Earnings	$	73.6


1			See Caution Concerning Non-GAAP Measures.



Algonquin Power & Utilities Corp. - Management Discussion & Analysis			21

2025 Annual Regulated Services Group Operating Results

For the twelve months ended December 31, 2025, the Regulated Services Group reported revenue of $2,333.7 million (comprised of $1,292.7 million of regulated electricity distribution revenue, $614.4 million of regulated natural gas distribution revenue and $426.6 million of regulated water reclamation and distribution revenue) as compared to revenue of $2,228.6 million in the same period in the prior year (comprised of $1,276.1 million of regulated electricity distribution revenue, $546.4 million of regulated natural gas distribution revenue and $406.1 million of regulated water reclamation and distribution revenue).

For the twelve months ended December 31, 2025, the Regulated Services Group reported net earnings of $351.0 million as compared to $260.1 million in the comparable period in the prior year.

Highlights of the changes are summarized in the following table:


(all dollar amounts in $ millions)	Twelve months ended December 31
Prior Period Net Earnings	$	260.1

Regulated Services Group EBIT1:
Electricity: Increase is primarily due to: –a $5.5 million true-up recorded in the first quarter of 2024 at the Empire District Electric System –favourable weather, which resulted in an increase of net earnings of approximately $13.9 million at the Empire District Electric System –the implementation of approved rates at the BELCO Electric System of $6.3 million (2024 approved rates were effective in the second quarter of 2024) –lower operating expenses of approximately $11.0 million including $4.0 million favourable impact from an adjustment recorded in 2024, with the remaining decrease driven by lower labour and maintenance expenses Partially offset by: –additional expense of $8.5 million in respect of a targeted relief initiative for customers agreed to as part of the Empire District Electric System (MO) rate case settlement –a write-off of $7.3 million related to the discontinuation of a solar project at the CalPeco Electric System –higher depreciation across all utilities of $5.6 million partially offset by a depreciation deferral adjustment of $4.8 million related to Granite State Electric System –lower interest income on regulatory asset accounts of approximately $3.0 million	14.4
Gas: Increase is primarily due to: –the implementation of approved rates of $16.8 million at the Midstates (MO) and Peach State (GA) Gas Systems –higher net revenue of $1.9 million from the Gas System Enhancement Program at the New England (MA) Gas System –lower bad debt expense of $6.9 million –a depreciation deferral adjustment of $7.1 million related to the EnergyNorth (NH) Gas System in 2025 and a depreciation adjustment in 2024 at the Peach State (GA) Gas System of $1.9 million, partly offset by higher depreciation across the majority of gas systems of $6.2 million –increase in other income of $5.6 million at the Empire (MO) Gas System relating to a rate case adjustment due to over-amortization of pension and Other Post-Employment Benefits balance –a write-off of $6.8 million at the EnergyNorth (NH) Gas System in the fourth quarter of 2024 Partially offset by: –expenses of approximately $3.2 million relating to the Lexington gas incident –higher property taxes of approximately $3.1 million	35.9



Algonquin Power & Utilities Corp. - Management Discussion & Analysis			22


(all dollar amounts in $ millions)	Twelve months ended December 31
Water: Increase is primarily due to: –the implementation of approved rates of $18.5 million at the Arkansas (AR), Missouri Water (MO), New York (NY) (2024 approved rates were effective to the third quarter of 2024, retroactive to the second quarter of 2024) and Bella Vista (AZ), Beardsley (AZ), Cordes Lake (AZ) Water Systems and Rio Rico (AZ) Water and Sewer System –lower operating expenses of approximately $6.5 million at the New York Water (NY) Water System primarily due to lower labour expenses and a write off of $1.7 million recorded in 2024 Partially offset by: –higher depreciation expenses of $7.0 million –rate case adjustment of $3.3 million at the Litchfield Park (AZ) Water and Sewer System –lower interest income of approximately $1.2 million	11.8
Other: Increase is primarily due to the gain of $9.1 million on the settlement of a swap at the BELCO Electric System	9.2
Interest expense: Decrease primarily due to the repayment of debt with the proceeds of the Renewables Sale and the sale of the Company's investment in Atlantica which were partially pushed down into the Regulated Services Group	50.4
Income tax expense: Increase primarily due to higher earnings before tax	(29.2)
Net effect of non-controlling interests: Decrease primarily due to lower wind production resulting in lower HLBV	(1.6)
Current Period Net Earnings	$	351.0
1 See Caution Concerning Non-GAAP Measures.



Algonquin Power & Utilities Corp. - Management Discussion & Analysis

Regulatory Proceedings

The following table summarizes the major regulatory proceedings currently underway or completed or effective in 2025 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, BELCO filed its revenue allowance application in which it requested a $34.8 million increase for 2022 and a $6.1 million increase for 2023. On March 18, 2022, the Regulatory Authority ("RA") approved an annual increase of $22.8 million, for a revenue allowance of $224.1 million for 2022 and $226.2 million for 2023. The RA authorized a 7.16% rate of return, comprised of a 62% equity and an 8.92% return on equity ("ROE"). In April 2022, BELCO filed an appeal in the Supreme Court of Bermuda challenging the decisions made by the RA through the recent Retail Tariff Review. On February 23, 2024, the Bermuda Supreme Court issued an order denying the BELCO appeal. On April 11, 2025, BELCO and the RA filed a consent order with the court thereby concluding the matter.

Midstates Gas

Missouri

GRC

$13.2

On February 9, 2024, Midstates Gas filed an application seeking an increase in revenues of $13.2 million based on an ROE of 10.80% and an equity ratio of 52.92%. On July 18, 2024, the Staff of the Missouri Public Service Commission ("MPSC") and Office of the Public Counsel ("OPC") filed direct testimony. Staff proposed a base revenue increase of $4.4 million based on a 50% equity ratio and 9.45% ROE. OPC recommended a 47.5% equity ratio and 9.50% ROE. On August 22, 2024, the parties filed rebuttal testimony. On September 19, 2024, the parties filed surrebuttal testimony. On October 9, 2024, Staff filed a motion to suspend the procedural schedule and evidentiary hearing given that the parties reached a settlement resolving all issues. The parties filed a stipulation agreement on October 22, 2024 agreeing to an increase in annual distribution revenues of $9.1 million. On November 6, 2024, the MPSC unanimously voted to approve the settlement agreement. A written order was issued January 2, 2025 with approved rates effective January 8, 2025.

Missouri Water

Missouri

GRC

$8.1

On March 13, 2024, Missouri Water filed an application seeking an increase in revenues of $8.1 million based on an ROE of 10.62% and an equity ratio of 52.6%. On August 20, 2024, Staff filed direct testimony recommending an increase in annual revenues of $7.8 million based on an ROE of 9.45% and an equity ratio of 50%. The City of Bolivar recommended an increase in annual revenues of $7.5 million. On September 27, 2024, the parties filed rebuttal testimony. Surrebuttal testimony was filed on October 24, 2024. On December 6, 2024, a Unanimous Global Stipulation & Agreement was filed with the MPSC with an annual revenue increase of approximately $6.2 million. The MPSC issued an order approving the settlement on January 23, 2025. Approved rates became effective on March 1, 2025.



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

Utility

Jurisdiction

Regulatory Proceeding Type

Rate Request
(millions)

Current Status

Arkansas Water

Arkansas

GRC

$2.3

On March 14, 2024, Arkansas Water filed an application seeking an increase in revenues of $2.3 million based on an ROE of 10.62% and an equity ratio of 52.5%. On August 27, 2024, Staff filed testimony recommending an annual revenue increase of $1.5 million, based on an ROE of 9.80%. On September 24, 2024, the Company filed rebuttal testimony updating its proposed annual revenue increase to $1.8 million. Surrebuttal testimony was filed by the parties on October 22, 2024 and the Company's surrebuttal testimony was filed on October 29, 2024. On November 12, 2024, the Company and the Staff of the Arkansas Public Service Commission ("APSC") filed a settlement with an annual revenue increase of $1.5 million. On January 14, 2025, the APSC issued an order approving the settlement agreement and ordered compliance tariffs to be filed within seven days of the January 14, 2025 order. The APSC approved the compliance tariffs on February 7, 2025. Approved rates became effective on March 1, 2025.

New Brunswick Gas

New Brunswick

GRC

C$1.6

On April 15, 2024, New Brunswick Gas filed an application seeking an increase in revenues of C$1.6 million based on an ROE of 9.80% and an equity ratio of 45%. On August 16, 2024, the Office of the Public Intervenor filed testimony. On September 27, 2024, the Company filed rebuttal testimony. An evidentiary hearing was held on October 4, 7 and 8, 2024. On December 31, 2024, the New Brunswick Energy & Utilities Board (the "Board") issued an order authorizing an annual increase in revenue of C$1.2 million; on April 30, 2025, the Board issued its Reasons for Decision.

Bella Vista Water, Beardsley Water, Cordes Lakes Water, Rio Rico Water & Sewer

Arizona

GRC

$6.0

On December 28, 2023, Bella Vista Water, Beardsley Water, Cordes Lakes Water, and Rio Rico Water & Sewer filed an application seeking an increase in revenues of $6.0 million based on an ROE of 10.95% and an equity ratio of 54%. On June 26, 2024, the Arizona Corporation Commission ("ACC") granted the Company's request to extend the procedural schedule with a hearing on the merits scheduled for March 24-28, 2025. Staff testimony, which recommended an increase of $2.9 million in revenue based on an ROE of 9.4% and an equity ratio of 54%, was filed and supplemented on January 8, 2025. On February 5, 2025, the Company notified the ACC that the parties had reached a settlement in principle that would resolve all matters in the rate case. The parties filed a settlement agreement on February 21, 2025, which would result in an increase in revenues of $4.2 million. On March 25-26, 2025, the ACC held a hearing on the settlement agreement. On June 18, 2025, the ACC approved the settlement agreement with approved rates taking effect July 1, 2025.



Algonquin Power & Utilities Corp. - Management Discussion & Analysis

Utility

Jurisdiction

Regulatory Proceeding Type

Rate Request
(millions)

Current Status

Granite State Electric

New Hampshire

GRC

$15.5

On May 5, 2023, Granite State Electric 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 ("DOE") filed a motion seeking to dismiss the case. An evidentiary hearing was held on January 23, 2024. The case was stayed by the New Hampshire Public Utilities Commission ("NHPUC") until May 15, 2024 so that it may contemplate the motion and the Company's third-party review of its financial information. On April 2, 2024, the NHPUC directed the Company to cooperate with the DOE and all other parties to develop a mutually-agreeable scope of work for the third-party report, to be filed with the NHPUC no later than April 15, 2024. Because there was no agreement on the scope of work, the Company filed the third-party report which concluded that the accounting information included in the rate filing provides a sufficient basis for determining the Company's revenue requirement and that 2023 accounting data provides a sufficient basis for inclusion in the Company's regulatory filings. On April 24, 2024, the Company filed an updated revenue requirement, seeking an increase in revenues of $14.7 million. On April 30, 2024, the NHPUC rejected the scope of the third-party report that was submitted, ordered an independent audit facilitated by the DOE with a procedural schedule for the next phase of the proceeding due no later than May 20, 2024, and deferred a ruling on the DOE motion to dismiss. The NHPUC extended the stay until September 16, 2024 to assess the issues that were raised in the docket and called for a status report required by August 30, 2024. On September 30, 2024, the Company notified the NHPUC that the parties were engaged in settlement discussions. The parties filed a settlement agreement on November 18, 2024. A hearing on the settlement agreement was held on January 15, 2025. Initial briefs on the NHPUC's authority to approve the settlement were filed January 31, 2025. A hearing was held March 20, 2025. On March 25, 2025, the NHPUC issued a Procedural Order approving the settlement agreement which resulted in a $5.5 million increase in annual revenues. Approved rates took effect April 1, 2025. On April 24, 2025, the NHPUC issued a further order stating its reasons for approval of the settlement agreement.

BELCO

Bermuda

GRC

$2.9

BELCO requested, via data provided to the RA in 2025, an increase in revenue of $1.9 million for 2026 and $1.0 million for 2027 (excluding fuel costs) based on an ROE of 12.36% for both years and an equity ratio of 62%. On November 3, 2025, the RA authorized a 7.85% rate of return, comprised of a 62% equity and a 9.38% ROE. The RA approved an incremental revenue decrease of $3.6 million for 2026 and increase of $2.0 million for 2027 (excluding fuel costs).



Algonquin Power & Utilities Corp. - Management Discussion & Analysis

Utility

Jurisdiction

Regulatory Proceeding Type

Rate Request
(millions)

Current Status

EnergyNorth Gas

New Hampshire

GRC

$27.5

On July 27, 2023, EnergyNorth Gas 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 NHPUC on October 31, 2023. The temporary increased revenue requirement 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 NHPUC with a third-party review of the financial information upon which the revenue requirement is predicated. On February 16, 2024, the DOE filed a motion seeking to dismiss the case. On March 14, 2024, the NHPUC issued an order staying the case until June 7, 2024, so that it may contemplate the motion and so that the Company can provide the NHPUC with a third-party review of the financial information within the rate application. On April 17, 2024, the Company filed a proposed scope for the third-party review. On August 16, 2024, the DOE filed a status update informing NHPUC that the parties met to discuss a comprehensive settlement of all issues in the case and intend to more fully engage in settlement discussions once a settlement in the Granite State Electric case was reached. On November 20, 2024, the NHPUC extended the stay of the proceeding to accommodate settlement negotiations until January 21, 2025. On April 21, 2025, the NHPUC further extended the stay of the proceeding until May 30, 2025. On June 13, 2025, a settlement agreement was filed with the NHPUC supporting a continuation of rates approved on October 31, 2023. A hearing on the settlement was held July 31, 2025. On August 26, 2025, NHPUC issued a procedural order approving the settlement agreement in its entirety and approved distribution rates to be effective on September 1, 2025. On October 16, 2025, the NHPUC issued a Recommended Form for Memorialization Order and requested that the Commission approve such form of Order by the first week of November 2025. On November 7, 2025, the NHPUC issued its order delineating its reasoning for approval of the settlement agreement on permanent rates, thereby concluding the case.



Algonquin Power & Utilities Corp. - Management Discussion & Analysis

Utility

Jurisdiction

Regulatory Proceeding Type

Rate Request
(millions)

Current Status

Pending Rate Reviews

Park Water

California

GRC

$9.3

On January 2, 2024, Park Water 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%. On July 24, 2024, the Public Advocates Office at the California Public Utilities Commission (the "California PUC") filed testimony recommending a $2.4 million decrease in revenues for 2025. On September 23, 2024, the Company served rebuttal testimony seeking $9.0 million revenue increase. Legal briefs were filed in December 2024. On December 5, 2024, in the Cost of Capital proceeding for Small Class A Water Utilities, the California PUC issued an order increasing Park Water's ROE to 9.57%. On May 30, 2025, the Commission authorized an interim increased revenue requirement of $0.9 million or 2.3%, effective July 1, 2025. The Company is currently awaiting a Commission decision on the rate application which is expected in May 2026.

Apple Valley Water

California

GRC

$3.1

On January 2, 2024, Apple Valley Water 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%. On July 24, 2024, the Public Advocates Office at the California PUC filed testimony recommending a $3.9 million decrease in revenues for 2025. On September 23, 2024, the Company served rebuttal testimony seeking $2.9 million revenue increase. Legal briefs were filed in December 2024. On December 5, 2024, in the Cost of Capital proceeding for Small Class A Water Utilities, the California PUC issued an order increasing Apple Valley Water’s ROE to 9.57%. On May 30, 2025, the Commission authorized an interim increased revenue requirement of $0.7 million, or 2.3%, effective July 1, 2025. The Company is currently awaiting a Commission decision on the rate application which is expected in May 2026.



Algonquin Power & Utilities Corp. - Management Discussion & Analysis

Utility

Jurisdiction

Regulatory Proceeding Type

Rate Request
(millions)

Current Status

CalPeco Electric

California

GRC

$39.8

On September 20, 2024, CalPeco Electric filed an application seeking a net increase in total customer rates of $39.8 million including an increase of $64 million in base revenues based on an ROE of 11%, an equity ratio of 52.5% and current revenues at the time of filing. The requested base revenue increase was partially offset by the conclusion of $24.2 million of customer surcharge collections related to the 2022 general rate case, which were in effect at the time of filing and concluded in January 2025. On March 5, 2025, the Company filed a Motion for Interim Rate Relief and Request for Expedited Treatment in which it requested an interim rate recovery of 50% of its proposed base revenue requirement on a monthly basis beginning June 1, 2025 until issuance of a final decision in the proceeding. The Utility Reform Network ("TURN") and the Public Advocates Office ("Cal Advocates") opposed the Company’s request. On July 2, 2025, Cal Advocates, TURN and other intervenors in the proceeding filed testimony. Cal Advocates recommended an overall net increase in customer rates of $24.8 million. The Company served rebuttal testimony on July 24, 2025. Evidentiary hearings were held the week of September 15, 2025. On October 1, 2025, the Company submitted a joint motion requesting approval of a settlement agreement reached with majority of the Cal Advocates, TURN and other intervenors in the proceeding, which resolves all revenue requirement matters except ROE. The settlement agreement would result in a net increase in total customer rates of $24.8 million based on the Company's current authorized ROE of 10%. Legal briefs were filed on October 24, 2025. A proposed decision was issued on February 13, 2026 that would result in a net increase in total customer rates of $23.8 million and an increase of $48.6 million in base revenues based on a ROE of 9.75% and an equity ratio of 52.5%. The proposed decision adopts the settlement agreement provisions with the exception of rejecting the proposed fixed charge for residential customers. Comments on the proposed decision were filed on March 5, 2026.



Algonquin Power & Utilities Corp. - Management Discussion & Analysis

Utility

Jurisdiction

Regulatory Proceeding Type

Rate Request
(millions)

Current Status

Empire Electric

Missouri

GRC

$168.0

On November 6, 2024, Empire Electric filed an application seeking an increase in net operating revenues of $92.1 million based on an ROE of 10% and an equity ratio of 53.1%. On February 3, 2025, Staff of the MPSC and the Office of the Public Counsel filed motions to dismiss the case. The Company withdrew its tariff sheets on February 26, 2025 and refiled revised tariff sheets on the same day seeking a base rate revenue increase of $152.8 million. When considering the rebasing of test year revenues for fuel and purchased power costs and the energy efficiency cost recovery rate, the filing continues to seek a net operating revenue increase of $92.1 million. On March 5, 2025, the MPSC suspended the new tariff sheets until January 2, 2026. On April 10, 2025, the MPSC approved a procedural schedule for the case and on April 23, 2025, the Commission extended the true-up period from September 30, 2024 to March 31, 2025. The Company’s final true-up position reflected an annual revenue increase of approximately $168 million, primarily driven by projected higher natural gas costs required to operate its generating units. The MPSC Staff’s position supported an increase of about $128 million, while OPC recommended no increase, citing ongoing billing issues. To resolve these differences, the Company entered into a global non-unanimous stipulation agreement providing for an annual revenue increase of $97 million, with the potential to earn an additional $13 million annually if certain billing and customer service metrics are met. OPC and Consumers Council of Missouri did not join the settlement, and as a result of their objections, a hearing was held during the week of October 13, 2025. During the hearing, settlement terms were presented as position statements from the signatories. On November 5, 2025, the MPSC deliberated on the case and requested amendments to incorporate customer satisfaction performance metrics. The original signatories of the non-unanimous stipulation agreement submitted performance metrics in December 2025. The Commission held an on the record proceeding on January 7, 2026 related to the performance metrics. On January 14, 2026, the Commission issued its Report and Order effective January 24, 2026 approving the settlement agreements which will allow for the $97 million to be phased in over 3 years once the performance metrics have been met for three consecutive months. The Company will have the ability to earn the additional $13 million annually if it meets additional Customer First Performance metrics with those additional metrics to be agreed and filed with the Commission by May 31, 2026. On January 23, 2026, the Office of Public Counsel filed an application for rehearing and request for reconciliation. On February 5, 2026, the Commission issued an order denying the application for rehearing. On February 19, 2026, the Office of Public Counsel filed a Notice of Election to Not Appeal the Commission’s January 14 Report and Order.



Algonquin Power & Utilities Corp. - Management Discussion & Analysis

Utility

Jurisdiction

Regulatory Proceeding Type

Rate Request
(millions)

Current Status

St. Lawrence Gas

New York

GRC

$2.2

On November 27, 2024, St. Lawrence Gas filed an application seeking an increase of revenues of $2.2 million based on an ROE of 9.9% and an equity ratio of 48%. On April 1, 2025, Staff of the New York Department of Public Service recommended a $1.19 million decrease in rates. On April 22, 2025, the Company submitted rebuttal testimony requesting approximately $2.33 million. The Company filed notice and began confidential settlement negotiations on May 6, 2025. An unopposed Joint Proposal was filed on August 29, 2025 proposing a three-year rate plan ("Rate Plan") from November 1, 2025 through October 31, 2028 with unlevelized rate increases of $0.4M in Rate Year 1, $1.9M in Rate Year 2, and $1.6M in Rate Year 3. Base rate increases will be levelized to reduce rate volatility to customers over the term of the Rate Plan. The Joint Proposal established ROE at 9.3%, and equity ratios of 46% in Rate Year 1, 47% in Rate Year 2, and 48% in Rate Year 3. The Rate Plan includes an Earnings Sharing Mechanism, gas safety and customer service performance metrics, customer programs to assist low-income customers, and a three-year capital investment plan. The Joint Proposal also resolves the Company's outstanding Automated Meter Reading project petition providing funding to support the investment as part of the Rate Plan. The Joint Proposal includes provisions intended to further New York State's ability to meet the goals of the Climate Leadership and Community Protection Act. On January 22, 2026, the NYPSC approved the Joint Proposal.



Algonquin Power & Utilities Corp. - Management Discussion & Analysis

Utility

Jurisdiction

Regulatory Proceeding Type

Rate Request
(millions)

Current Status

New England Natural Gas

Massachusetts

GRC

$55.8

On June 13, 2025, New England Natural Gas filed an application seeking an increase of revenues of $55.8 million based on an ROE of 9.9% and an equity ratio of 53%. The request includes approximately $30 million of previously authorized Gas System Enhancement Program rate base and a 5 year performance based ratemaking plan. A comprehensive settlement agreement was filed on January 30, 2026. The proposed settlement provides for a $45.3 million increase in distribution revenues, of which $27.4 million relates to prior investments under the Gas System Enhancement Program (“GSEP”) and previously included in revenues. The settlement includes two rate base resets. The July 1, 2027 rate base reset would allow recovery of $13.0 million of 2026 pipeline safety investments, $6.7 million of Q4 2025 non-GSEP investments, and up to $13.3 million of 2026 non-GSEP, non-pipeline safety investments. The July 1, 2028 rate base reset would allow recovery of the remaining 2026 non-GSEP deferred additions (up to $13.3 million), $13.9 million of 2027 pipeline safety investments, up to $26.5 million of 2027 non-GSEP projects, and recovery of the 2026 non-GSEP deferred regulatory asset. The settlement reflects a capital structure of 47.1% debt and 52.9% equity, with an authorized return on equity of 9.3%. The Pension Adjustment Factor would be rolled into base rates, with an approximately $9.5 million over-recovery credited to customers in 2026. In addition, $41.6 million of deferred GSEP costs would be recovered over 10 years through the GSEP beginning July 1, 2027, with carrying charges on the unrecovered balance at the Company’s money pool rate. The Company agreed to no further increase or redesign of base distribution rates before November 1, 2029. A decision was requested by March 27, 2026, and new rates would be effective April 1, 2026, if approved. The Company is awaiting a Commission decision.

Litchfield Park Water & Sewer

Arizona

GRC

$17.8

On June 30, 2025, Litchfield Park Water & Sewer filed rate applications with the Arizona Corporation Commission for its water and wastewater systems, requesting a combined revenue increase of $17.8 million. The request is based on an ROE of 10.8% and an equity ratio of 54%. As part of the application, the Company is seeking approval for the implementation of an annual formula rate based adjustment mechanism. On January 16, 2026, ACC Staff filed testimony which recommends a combined revenue increase of $14.5 million based on an ROE of 9.45% and an equity ratio of 54%. The Company filed rebuttal testimony on February 25, 2026. On March 3, 2026, the Company and Commission Staff jointly submitted a settlement agreement that resolves all matters between the two parties and would result in a combined water and wastewater revenue increase of $15.3 million based on ROE of 9.75% and an equity ratio of 54%. The settlement agreement also proposes deferral of the formula rate request to a separate Phase II of the proceeding. The Residential Utility Consumer Office is not party to the settlement agreement. Hearings are scheduled for the week of March 23, 2026.



Algonquin Power & Utilities Corp. - Management Discussion & Analysis

Utility

Jurisdiction

Regulatory Proceeding Type

Rate Request
(millions)

Current Status

CalPeco Electric

California

Wildfire Expense Memorandum Application

$78.2

On June 20, 2025, CalPeco Electric filed an application to recover $78.2 million in costs associated with the 2020 Mountain View Fire recorded in the Wildfire Expense Memorandum Account. These costs include claim settlements in excess of Liberty’s wildfire insurance coverage, legal costs, and financing costs related to the Mountain View Fire. On December 12, 2025, Cal Advocates and Small Business Utility Advocates ("SBUA") filed testimony opposing the Company’s request. Cal Advocates does not put forward a specific disallowance proposal and SBUA proposes a full disallowance of Liberty's request. Liberty's rebuttal testimony was submitted on January 23, 2026. Hearings were held February 10-11, 2026.

Empire Electric

Kansas

GRC

$15.8

On December 31, 2025 Empire Electric filed an application to increase its Kansas retail electric base rates of $15.8 million, approximately 93.77%. If the Commission approves Empire's request to include the costs of its wind projects, in base rates, then a portion of the increase in base rates will be offset by an expected reduction in fuel costs of approximately $3.3 million per year, reducing the proposed increase in the residential customer's overall bill to 40%. The Company has also proposed a three-year phase-in of rates.



Algonquin Power & Utilities Corp. - Management Discussion & Analysis

CORPORATE GROUP NET EARNINGS AND ADJUSTED NET EARNINGS

Key financial information related to the Corporate Group is as follows:


2025 Fourth Quarter and Annual Corporate Group Net Loss and Adjusted Net Loss1,2
	Three months ended		Twelve months ended
	December 31		December 31
(all dollar amounts in $ millions)	2025	2024	2025	2024
Revenue	0.4	(0.2)	1.5	0.8
Less: Operating expenses	2.3	3.7	5.3	9.4
Less: (Gains)/Loss on foreign exchange	2.8	(0.3)	18.4	3.5
Less: Depreciation and amortization	0.2	0.2	0.9	2.1

Add: Interest, dividend and other income	3.9	12.3	14.7	79.9
Add: Change in value of investments carried at fair value	—	(2.1)	—	21.4
Less: Other expenses

Other losses	(10.8)	3.2	(22.9)	(9.2)
Gain/(Loss) on derivative financial instruments	—	—	(7.4)	1.5
Corporate Group EBIT1,3	(11.8)	9.6	(38.7)	79.4
Less: Interest expense	(35.4)	(42.7)	(140.2)	(170.9)
Less: Income tax (loss) recovery	3.5	(137.4)	15.3	(115.6)

Corporate Group Net Loss attributable to shareholders	(43.7)	(170.5)	(163.6)	(206.8)
Less: Series A Shares and Series D Shares dividend	(2.6)	(2.7)	(10.5)	(10.5)
Corporate Group Net Loss attributable to common shareholders	(46.3)	(173.2)	(174.1)	(217.3)
Add / (Less): Adjusted items
Loss/(Gain) on derivative financial instruments	0.3	(0.4)	(1.5)	(0.8)
Restructuring costs4	16.7	7.1	38.7	27.0
(Gain)/Loss on foreign exchange	2.8	(0.3)	18.4	3.5
Change in value of investments carried at fair value	(0.1)	2.0	(0.2)	(21.7)
Adjustment for taxes related to above	(1.9)	144.3	(4.6)	158.8
Corporate Group Adjusted Net Loss1	(28.5)	(20.5)	(123.3)	(50.5)


1			See Caution Concerning Non-GAAP Measures.
2			This table contains a reconciliation of Adjusted Net Earnings to net earnings for the Corporate Group. The relevant sections of the table are derived from and should be read in conjunction with the audited consolidated statement of operations and Note 19 in the audited consolidated financial statements, "Segmented Information". This supplementary disclosure is intended to more fully explain disclosures related to Adjusted Net Earnings for the Corporate Group and provides additional information related to the operating performance of the Corporate Group. Investors are cautioned that Adjusted Net Earnings should not be construed as an alternative to net earnings.
3			This table contains a reconciliation of EBIT to net earnings for the Corporate Group. The relevant sections of the table are derived from and should be read in conjunction with the audited consolidated statement of operations and Note 19 in the audited consolidated financial statements, "Segmented Information". This supplementary disclosure is intended to more fully explain disclosures related to EBIT and provides additional information related to the operating performance of the Corporate Group. Investors are cautioned that EBIT should not be construed as an alternative to net earnings.
4			See Note 17 in the audited consolidated financial statements.

For the three and twelve months ended December 31, 2025, interest, dividend and other income includes dividends from Atlantica of $nil as compared to $10.9 million and $76.3 million, respectively, during the same periods in 2024. Similarly, for the three and twelve months ended December 31, 2025, change in investments carried at fair value was $nil as compared to a gain of $2.1 million and $21.4 million, respectively, in the same periods in 2024. The decrease is due to the sale of the Company's ownership interest in Atlantica on December 12, 2024.

During the three and twelve months ended December 31, 2025, interest expense totaled $35.4 million and $140.2 million as compared to $42.7 million and $170.9 million, respectively, in the same periods in 2024. The decrease was primarily driven by lower borrowing due to the use of the proceeds from sale of the Company's investment in Atlantica and the Renewables Sale to repay indebtedness.



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

For the three and twelve months ended December 31, 2025, other net losses primarily related to restructuring costs (including third party consulting charges) of $16.7 million and $38.7 million, respectively, as compared to $7.1 million and $27.0 million, respectively, during the same periods in 2024.



Algonquin Power & Utilities Corp. - Management Discussion & Analysis

HYDRO GROUP NET EARNINGS

Key financial information related to the Hydro Group is as follows:


2025 Fourth Quarter and Annual Hydro Group Net Earnings1
	Three months ended				Twelve months ended
	December 31				December 31
(all dollar amounts in $ millions)	2025		2024		2025		2024




Revenue	$	8.4	$	8.1	$	36.5	$	35.3
Other revenue	0.5		—		1.2		0.8
Less: Other cost of sales	—		—		—		0.3
Less: Operating expenses	3.0		2.0		11.2		8.8
Less: Depreciation and amortization	1.8		1.8		7.3		6.8
Add: Interest, dividend and other income	(0.1)		—		0.1		—
Add: Other gains	—		—		0.7		—
Hydro Group EBIT2	4.0		4.3		20.0		20.2
Less: Interest expense	(0.2)		(0.2)		(0.9)		(0.9)
Less: Income tax (expense) / recovery3	(0.8)		(0.8)		15.9		(4.2)
Net earnings from non-controlling interest	(0.9)		(0.8)		(3.9)		(3.1)
Hydro Group Net Earnings	$	2.1	$	2.5	$	31.1	$	12.0


1			This table contains a reconciliation of EBIT to net earnings for the Hydro Group. The relevant sections of the table are derived from and should be read in conjunction with the audited consolidated statement of operations and Note 19 in the audited consolidated financial statements, "Segmented Information". This supplementary disclosure is intended to more fully explain disclosures related to EBIT and provides additional information related to the operating performance of the Hydro Group. Investors are cautioned that EBIT should not be construed as an alternative to net earnings.
2			See Caution Concerning Non-GAAP Measures.
3			For the twelve months ended December 31, 2025, income tax primarily relates to $15.9 million of income tax recovery from the tax basis step-up during Hydro Group's asset reorganization related to the Renewables Sale.



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

DISCONTINUED OPERATIONS: RENEWABLE ENERGY GROUP

The former renewable energy group (excluding hydro), presented as discontinued operations, generated and sold 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 (excluding hydro) was sold by the Company on January 8, 2025.

Key financial information related to the discontinued operations is as follows:


2025 Fourth Quarter and Annual Discontinued Operations Results
	Three months ended				Twelve months ended
	December 31				December 31
(all dollar amounts in $ millions)	2025		2024		2025		2024




Revenue	$	—	$	99.2	$	7.4	$	339.7
Operating income (loss)	$	—	$	57.3	$	(1.3)	$	47.9



Net loss attributable to AQN	$	(11.0)	$	(78.9)	$	(37.7)	$	(1,445.8)

Due to the Renewables Sale, for the three and twelve months ended December 31, 2025, the renewable energy group's facilities generated operating revenue of $nil and $7.4 million, respectively, as compared to $99.2 million and $339.7 million, respectively, in the comparable periods in the prior year. The net loss attributable to the Company for the three and twelve months ended December 31, 2025, was $11.0 million and $37.7 million, respectively, and was primarily driven by finalization of certain closing adjustments. The net loss attributable to the Company for the same periods in 2024 was $78.9 million and $1,445.8 million, respectively. The net loss attributable to the Company for the three and twelve months ended December 31, 2024 was primarily driven by an impairment loss of $55.7 million and $1,357.3 million on the assets of the renewable energy group (excluding hydro) upon classification as held-for-sale.

Due to the Renewables Sale, during the three months ended December 31, 2025, cash provided by operating activities was $nil as compared to $41.8 million during the same period in 2024. Cash used in investing activities was $nil as compared to $61.7 million during the same period in 2024. During the twelve months ended December 31, 2025, cash provided by operating activities was $nil as compared to $121.3 million during the same period in 2024. Cash used in investing activities was $nil as compared to $196.0 million during the same period in 2024.



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

NON-GAAP FINANCIAL MEASURES

Reconciliation of EBIT to Net Earnings

The following table is derived from and should be read in conjunction with the audited consolidated statement of operations. This supplementary disclosure is intended to more fully explain disclosures related to EBIT of AQN 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)	2025		2024		2025		2024
Net earnings (loss) attributable to common shareholders	$	18.4	$	(189.1)	$	170.3	$	(1,391.0)
Add: Series A Shares and Series D Shares dividend	2.6		2.7		10.5		10.5
Net earnings (loss) attributable to shareholders	21.0		(186.4)		180.8		(1,380.5)

Add (deduct):
Income tax expense	11.2		153.5		65.0		186.8
Net effect of non-controlling interest	(21.6)		(19.7)		(72.5)		(74.9)
Loss from discontinued operations, net of tax	11.0		78.9		37.7		1,445.8
Interest expense	71.6		89.5		282.5		363.6
EBIT	$	93.2	$	115.8	$	493.5	$	540.8



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 audited consolidated statement of operations. This supplementary disclosure is intended to more fully explain disclosures related to Adjusted Net Earnings of AQN 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.

The following table shows the reconciliation of net earnings (loss) attributable to common shareholders to Adjusted Net Earnings of AQN exclusive of these items:


	Three months ended				Twelve months ended
	December 31				December 31
(all dollar amounts in $ millions except per share information)	2025		2024		2025		2024
Net earnings (loss) attributable to common shareholders	$	18.4	$	(189.1)	$	170.3	$	(1,391.0)
Add (deduct):
Loss from discontinued operations, net of tax	11.0		78.9		37.7		1,445.8

Gain (loss) on derivative financial instruments	0.3		(0.4)		(1.5)		(0.8)


Restructuring costs1	16.7		7.1		38.7		27.0

Loss (gain) on foreign exchange	2.8		(0.3)		18.4		3.5



Change in value of investments carried at fair value2	(0.1)		2.0		(0.2)		(21.7)



Adjustment for taxes related to above	(1.9)		144.3		(4.6)		158.8
Adjusted Net Earnings	$	47.2	$	42.5	$	258.8	$	221.6
Adjusted Net Earnings per common share	$	0.06	$	0.06	$	0.34	$	0.30



1			See Note 17 in the audited consolidated financial statements.

2			See Note 7 in the audited consolidated financial statements.

For the three months ended December 31, 2025, Adjusted Net Earnings totaled $47.2 million as compared to $42.5 million for the same period in 2024, an increase of $4.7 million.

For the twelve months ended December 31, 2025, Adjusted Net Earnings totaled $258.8 million as compared to $221.6 million for the same period in 2024, an increase of $37.2 million.



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

SUMMARY OF PROPERTY, PLANT AND EQUIPMENT EXPENDITURES


	Three months ended				Twelve months ended
	December 31				December 31
(all dollar amounts in $ millions)	2025		2024		2025		2024
Regulated Services Group
Sustaining1	$	190.4	$	231.4	$	499.7	$	610.5
Growth	$	29.9	$	27.4	$	103.8	$	146.7

	$	220.3	$	258.8	$	603.5	$	757.2





Hydro Group	$	2.4	$	1.7	$	5.3	$	6.6




Total Capital Expenditures	$	222.7	$	260.5	$	608.8	$	763.8


1			Capital spend to support existing systems (e.g. asset replacements, safety & reliability projects).

2025 Fourth Quarter Property, Plant and Equipment Expenditures

During the three months ended December 31, 2025, the Regulated Services Group made capital expenditures of $220.3 million as compared to $258.8 million during the same period in 2024. The decrease of $38.5 million is mainly due to unrepeated technology projects in 2025. The Regulated Services Group's investments during the fourth quarter of 2025 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, 2025, the Hydro Group made capital expenditures of $2.4 million as compared to $1.7 million during the same period in 2024. Investments during the fourth quarter of 2025 were primarily related to new construction and ongoing repairs and maintenance at existing operating facilities.

2025 Annual Property, Plant and Equipment Expenditures

During the twelve months ended December 31, 2025, the Regulated Services Group incurred capital expenditures of $603.5 million as compared to $757.2 million during the same period in 2024. The decrease of $153.7 million is mainly due to unrepeated technology projects in 2025. The Regulated Services Group's investments in 2025 were primarily related to the construction of transmission and distribution main replacements, work on new and existing substation assets, and initiatives relating to the safety and reliability of electric and natural gas systems.

During the twelve months ended December 31, 2025, the Hydro Group made capital expenditures of $5.3 million as compared to $6.6 million during the same period in 2024. Investments in 2025 were primarily related to new construction and ongoing repairs and maintenance at existing operating facilities.



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

LIQUIDITY AND CAPITAL RESERVES

AQN has revolving credit and letter of credit facilities as well as separate credit facilities for the Regulated Services Group to manage liquidity and working capital requirements (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, 2025:


	As at		As at
	December 31, 2025		December 31, 2024
(all dollar amounts in $ millions)	Total		Total
Revolving and term credit facilities1	$	1,928.5	$	2,380.3
Funds drawn on facilities / commercial paper issued	(420.0)		(814.8)
Letters of credit issued	(34.1)		(26.2)
Liquidity available under the facilities	1,474.4		1,539.3
Undrawn portion of uncommitted letter of credit facilities	(62.4)		(63.3)
Cash on hand	32.7		34.8
Total Liquidity and Capital Reserves	$	1,444.7	$	1,510.8
1 Includes a $75 million uncommitted standalone letter of credit facility and $78.5 million drawn term facilities of Suralis S.A. ("Suralis") as at December 31, 2025 ($180.3 million as at December 31, 2024).

Regulated Services Group

On June 24, 2025, the Regulated Services Group's $25.0 million senior unsecured revolving credit facility was terminated on its maturity date.

On July 10, 2025, the Regulated Services Group amended and restated its senior unsecured revolving credit facility (the "Bermuda Credit Facility") by decreasing the facility limit from $100.0 million to $25.0 million and extending the maturity to July 10, 2027. As at December 31, 2025, the Bermuda Credit Facility had $4.5 million drawn.

On November 13, 2025, the Regulated Services Group's $1.0 billion senior unsecured revolving credit facility (the "Long-Term Regulated Services Credit Facility") maturity date was extended from April 29, 2027 to November 13, 2030. As at December 31, 2025, the Long-Term Regulated Services Credit Facility had no amounts drawn and had $21.5 million of outstanding letters of credit.

On November 13, 2025, the Regulated Services Group increased the size of its unsecured commercial paper program by $500 million to $1.0 billion. This increased unsecured commercial paper program now permits the Regulated Services Group to issue, from time to time, unsecured commercial paper notes up to a maximum aggregate amount outstanding at any one time of $1.0 billion with varying maturities of up to 270 days from the date of issue. As at December 31, 2025, the Regulated Services Group had $337.0 million of commercial paper issued and outstanding.

Corporate Group

On November 13, 2025, the Corporate Group amended and restated its senior unsecured revolving credit facility (the "Corporate Credit Facility") by decreasing the facility limit from $1.0 billion to $750.0 million and removing sustainability-linked performance targets. As at December 31, 2025, the Corporate Credit Facility had no amounts drawn and had no outstanding letters of credit. The Corporate Credit Facility matures on March 31, 2028.

As at December 31, 2025, the Company had issued $12.6 million of letters of credit from its $75.0 million uncommitted letter of credit facility.

Long-Term Debt

On May 19, 2025, Liberty Utilities (CalPeco Electric) LLC repaid a $25.0 million senior unsecured utility note prior to its maturity on December 29, 2025.

On June 30, 2025, Liberty Utilities (Granite State Electric) Corp. repaid a $5.0 million senior unsecured utility note prior to its maturity on July 1, 2025.

Issuance of $200.0 Million of Senior Unsecured Notes



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

On July 10, 2025, BELCO completed a private placement offering of $200.0 million aggregate principal amount of 5.28% senior notes due June 14, 2030 (the "Senior Notes"). The Senior Notes are unsecured and unsubordinated obligations of BELCO and senior in right of payment to any existing and future subordinated indebtedness. BELCO used the net proceeds from the sale of the Senior Notes to repay certain existing indebtedness and for other general corporate purposes. On July 10, 2025, BELCO fully repaid its $49.5 million term loan facility ahead of its scheduled maturity of December 26, 2031. On July 10, 2025, BELCO fully repaid the $62.4 million drawn on its Bermuda Credit Facility.

Issuance of CLF 1.5 Million of Senior Unsecured Bond

On August 13, 2025, Suralis completed a private placement offering of CLF 1.5 million (equivalent to USD $61.6 million) aggregate principal amount of 3.30% senior utility bonds due July 10, 2034 (the "Senior Utility Bonds"). The Senior Utility Bonds are unsecured and unsubordinated obligations of Suralis and senior in right of payment to any existing and future subordinated indebtedness. Suralis used the net proceeds from the sale of the Senior Utility Bonds to repay certain existing indebtedness and for other general corporate purposes.

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 Morningstar DBRS ("DBRS") and a BBB issuer rating from Fitch Ratings Inc. ("Fitch").

Liberty Utilities Co. 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 Co. 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. The Empire District Electric Company 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. 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.

Contractual Obligations

Information concerning contractual obligations from continuing operations as of December 31, 2025 is shown below:


(all dollar amounts in $ millions)	Total		Due in less than 1 year		Due in 1 to 3 years		Due in 4 to 5 years		Due after 5 years
Principal repayments on debt obligations1,2	$	6,573.2	$	1,577.9	$	509.9	$	1,754.3	$	2,731.1
Advances in aid of construction	133.0		2.0		—		—		131.0
Interest on long-term debt obligations2	4,377.3		287.5		455.7		332.3		3,301.8
Purchase obligations	542.1		542.1		—		—		—
Environmental obligations	56.9		3.6		22.6		15.5		15.2
Derivative financial instruments:
Cross currency interest rate swaps	16.7		0.9		1.3		0.9		13.6
Commodity contracts	0.8		0.8		—		—		—
Purchased power	209.9		44.3		35.8		25.4		104.4
Gas delivery, service and supply agreements	477.2		109.3		113.3		95.1		159.5
Service agreements	21.7		12.6		9.1		—		—
Capital projects	1.1		2.1		—		—		—
Land easements	85.2		3.6		6.5		6.7		68.4
Other obligations	3.9		1.7		1.6		0.3		0.3
Total obligations3	$	12,499.0	$	2,588.4	$	1,155.8	$	2,230.5	$	6,525.3


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 audited consolidated financial statements.



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

Equity

The common shares of AQN are publicly traded on the Toronto Stock Exchange and the New York Stock Exchange under the trading symbol "AQN". As at March 5, 2026, AQN had 768,691,822 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 of directors of the Company (the "Board"). As at March 5, 2026, 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 6.853% annually for the five year period ending on March 31, 2029.

Declaration of 2026 First Quarter Dividend of $0.0650 (C$0.0888) per Common Share

The Board has declared a first quarter 2026 dividend of $0.0650 per common share payable on April 15, 2026 to shareholders of record on March 31, 2026.

The Canadian dollar equivalent for the first quarter 2026 dividend is C$0.0888 per common share.

Changes in the level of dividends paid by AQN are at the discretion of the Board, with dividend levels being reviewed periodically by the Board in the context of AQN's financial performance and growth prospects.

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


	Q2 2025		Q3 2025		Q4 2025		Q1 2026		Total
U.S. dollar dividend	$	0.0650	$	0.0650	$	0.0650	$	0.0650	$	0.2600
Canadian dollar equivalent	$	0.0897	$	0.0893	$	0.0918	$	0.0888	$	0.3596

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, 2025, 168,595,010 common shares representing approximately 22% of total common shares outstanding had been registered with the Reinvestment Plan.

SHARE-BASED COMPENSATION PLANS

As at December 31, 2025, the following share-based compensation awards were outstanding which may be exercised or settled, as applicable, for common shares of the Company:


Share-based compensation awards			Total
Options			1,684,228

Performance and Restricted Share Units			5,760,071
Director's Deferred Share Units			809,647
Bonus Deferral Restricted Share Units			80,828

AQN also 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. As at December 31, 2025, a total of 4,448,267 common shares had been issued under the ESPP.



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

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 the utilities' capital structures consistent with capital structures approved by regulators in the jurisdictions in which the Company 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;

•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.

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.

OPERATIONAL RISK MANAGEMENT

Mechanical and Operational Risks

AQN's profitability could be impacted by, among other things, equipment failure, the failure of a major customer to fulfill its contractual obligations, reductions in average energy prices, a strike or lock-out at a facility, natural disasters, diseases and other force majeure events, trade and tariff disputes, interruptions in supply chains and expenses related to claims or clean-up to adhere to environmental and safety standards.

The Company's water 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 from a water main break or equipment failure in a drinking water distribution system could result in severe injury, illness or death to those who consume the impacted water.

The Company’s wastewater collection system operates under either a pressurized system or flow under gravity conditions as approved by regulation. Should a sanitary spill occur due to blockage or sewer line break, this could result in a release of untreated wastewater resulting in severe injury, illness or damage to those who come into contact with untreated wastewater. The Company'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 Company'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 Company'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, damage caused by snow or ice to gas infrastructure, compromised system integrity, type/age of pipelines, and severe weather events. On February 2, 2026, an explosion and fire occurred in Nashua, New Hampshire, destroying a commercial building served by the gas distribution system of



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

EnergyNorth Natural Gas. No other structures were damaged and there were no fatalities. The National Transportation Safety Board is investigating and on March 5, 2026, issued a preliminary report.

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 which can result in lower than expected revenues. . 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 its facilities.

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 the Hydro Group’s hydroelectric facilities, water rights are owned by governments that reserve the right to control water levels, which may affect revenue. The failure to obtain all necessary licenses or permits for such facilities, including renewals thereof or modifications thereto, may result in an inability to operate the facility and could adversely affect cash generated from operating activities.

The Regulated Services Group’s facilities are subject to rate setting by its regulatory agencies. The Company 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. 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 Company 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 a regulated utility is the disallowance by the utility’s regulator of operating expenses or capital costs for which recovery is sought through regulatory proceedings. The Company has invested significant capital in its utilities for which it is or will be seeking cost recovery. There is a risk that the utilities’ regulators may not approve, or may otherwise delay recovery, of some or all of the Company’s invested capital. In certain jurisdictions, the Company's utilities may be exposed to infrastructure-related responsibilities (including stormwater or climate adaptation systems) for which there is limited or no established cost recovery framework. In addition, as the Company recently updated its technology infrastructure systems, there is additional risk that financial data required for rate filings could be difficult to produce or the data is deemed unreliable for ratemaking purposes. Further, there is additional risk that customer billing services may be deemed inadequate and such customer billing concerns could negatively impact the risk of disallowance and/or regulatory lag and may result in additional administrative actions and complaint proceedings against the Company and its operating subsidiaries. In addition, capital investments that have become stranded may pose additional risk for cost recovery and could be subject to legislation or rulings that would impact the extent to which such costs could be recovered. Similarly, recovery of extraordinary fuel expenses may pose additional risk for cost recovery and could be subject to legislation or regulatory action that would impact the extent to which such costs could be recovered. Further, there is a risk that utility regulators may scrutinize the Company's allocation of shared costs. If the Company is unable to recover increased costs of operations or its investments in new facilities, or in the event of significant regulatory lag, the Company's results of operations could be adversely affected.

Furthermore, the economies of Canada and the United States each experienced a significant rise in the inflation rate in the post-pandemic era compared to recent historical inflation rates. While the inflation rate has subsided due, in part, to actions taken by the Bank of Canada and the U.S. Federal Reserve System, there remains uncertainty in the near-term outlook as to whether inflation will remain elevated. Increases in inflation raise the Company’s costs for labour, materials and services, and a failure to recover these increased costs could result in under-recovery. Cost recovery efforts could also face resistance from customers and other stakeholders especially in a rising cost environment, whether due to inflation or high fuel prices or otherwise, and/or in periods of economic decline or hardship. Significant increases in costs also could increase financing needs and otherwise adversely affect the Company’s business, financial position and results of operations.



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In addition, there is a risk that the utility’s regulator will not approve the revenue requirements or rate adjustments requested in outstanding or future rate applications or will, on its own initiative, seek to reduce the existing revenue requirements or approved rates. Rate applications are subject to the utility regulator’s review process, usually involving participation from intervenors and other stakeholders that are involved in the case, and a public hearing process. There can be no assurance that resulting decisions or rate orders issued by the utility regulators will permit the Company to recover all costs actually incurred, costs of debt and income taxes, or to earn a particular return on equity.

Condemnation Expropriation Proceedings

The Company's distribution systems could be subject to condemnation or other methods of taking by government entities under certain conditions (including, without limitation, Liberty Utilities (Apple Valley Ranchos Water) Corp., which has been the subject of a condemnation lawsuit filed by the Town of Apple Valley and Liberty New York Water, which has received municipalization inquiries). There can be no assurance that the Corporation will receive fair market value for such assets or that the Corporation would not incur a loss.

Inflation Risk

AQN's profitability could be impacted by inflation increases above long-term averages. The Company'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 Company 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.

Development and construction projects could experience a decrease in expected returns as a result of increased costs.

Tariff Risk

Changes in tariffs may adversely affect the capital expenditures required to maintain, develop or construct the Company’s projects or infrastructure. In 2025, the U.S. government issued numerous executive orders imposing tariffs on goods from most countries around the world, including Canada, Mexico and China, as well as product-specific tariffs on various goods, such as steel, aluminum, copper and automobiles, and have indicated further measures may be under consideration. Several countries have similarly announced reciprocal or other tariffs impacting products manufactured or produced in the United States. New or existing trade agreements, including the ongoing review of the U.S.-Mexico-Canada Agreement, may also impact the tariff rate applicable to goods imported by the Company or its suppliers. Additionally, certain tariffs are subject to legal challenges. Accordingly, the situation is fluid and changes rapidly. Whether existing tariffs will be increased, decreased, or suspended altogether, as well as the imposition of additional tariffs by the U.S., the potential for further retaliation or tariff imposition by other countries, or any further adjustment to trade policies and tariffs and the timing thereof are difficult to predict at this time.

Tariffs may increase the cost of imported materials and equipment, disrupt supply chains, drive economic volatility, and create adverse capital and credit market conditions. The impact of tariffs on the cost of products and supplies used by the Company may increase the Company’s operating costs and elevate the cost of capital projects. Given the evolving nature of global trade policies, the Company cannot reasonably estimate the potential effects of current or future tariffs. Such effects could include project delays, cost increases, and other challenges to the execution of the Company’s strategic plans.

In addition, import restrictions, border delays and governmental seizures may also increase the cost of projects and result in construction and placed-in-service delays. These events could adversely affect the Company as a buyer and importer of goods, and ultimately impacts its 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 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



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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 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.

Asset Retirement Obligations

AQN and its subsidiaries complete periodic reviews of potential asset retirement obligations that may require recognition. As part of this process, AQN and its subsidiaries consider the contractual requirements outlined in their operating permits, leases, and other agreements, the probability of the agreements being extended, the ability to quantify such expense, the timing of incurring the potential expenses, as well as other factors which may be considered in evaluating if such obligations exist and in estimating the fair value of such obligations.

In conjunction with acquisitions and developed projects, the Company assumed certain asset retirement obligations. The asset retirement obligations mainly relate to legal requirements for: (i) removal or decommissioning of power generating facilities; (ii) cut (disconnect from the distribution system), purge (clean of natural gas and PCB contaminants), and cap natural gas mains within the natural gas distribution and transmission system when mains are retired in place, or dispose of sections of natural gas mains when removed from the pipeline system; (iii) clean and remove storage tanks containing waste oil and other waste contaminants; and (iv) remove asbestos upon major renovation or demolition of structures and facilities.

Cycles and Seasonality

The Company'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, or if government restrictions are imposed on water usage during drought conditions, the demand for water may decrease, adversely affecting revenues.

The Company's demand for energy from its electric distribution systems is primarily affected by weather conditions and conservation initiatives. The Company 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 Company'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 Company has successfully obtained regulatory approval to implement such decoupling mechanisms in 7 of 13 jurisdictions. 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.



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Development and Construction Risk

The Company engages in the development and construction of water and wastewater facilities, transmission and distribution assets and other complementary projects. In addition, each of the Company’s operating business units may occasionally undertake construction activities as part of normal course maintenance activities. There can be no assurance that the Company will be able to identify opportunities that improve the Company’s financial results or increase the amount of cash available for distribution. There is always a risk that material delays, technical issues with interconnection, required upgrades to interconnection facilities, required curtailments of generation and/or cost overruns or lost revenue could be incurred in any of the Company's future projects affecting the Company's overall performance. There are risks that actual costs may exceed budget estimates, delays may occur in obtaining permits and materials, suppliers and contractors may not perform as required under their contracts, warranties under contracts may be unfilled or insufficient, there may be inadequate availability, productivity or increased cost of qualified craft or local labour, start-up activities may take longer than planned, curtailment of a facility's output may be required, the scope, actual or expected returns, and timing of projects may change, and other events beyond the Company's control may occur, in each case that may materially affect the viability, schedule, budget, cost and performance of projects. Regulatory approvals can be challenged by a number of mechanisms which vary across federal, state and provincial jurisdictions. Such permitting challenges could identify issues that may result in permits being modified or revoked.

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 in dispute, and CAL FIRE has not yet released its final report. There were 22 lawsuits filed 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. Fifteen lawsuits were brought by groups of individual plaintiffs and a Native American group 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 15 lawsuits also alleges the wrongful death of an individual and various subrogation claims on behalf of insurance companies). In six other lawsuits, insurance companies alleged inverse condemnation and negligence and seek recovery of amounts paid and to be paid to their insureds. In one other 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. Liberty CalPeco has resolved 21 of the lawsuits, and Liberty CalPeco is in the process of obtaining dismissals with prejudice of said lawsuits. The trial date for the remaining lawsuit previously scheduled for April 15, 2025 was vacated. The likelihood of success in this lawsuit is uncertain. Liberty CalPeco intends to vigorously defend it. The Company accrued estimated losses of $178.4 million for claims related to the Mountain View Fire, against which Liberty CalPeco has recorded recoveries through insurance of $116.0 million and Wildfire Expense Memorandum Account ("WEMA") of $71.5 million. On June 20, 2025, the Company filed an application seeking recovery of $78.2 million, comprising of the costs recorded to date in the WEMA and $6.7 million of forecasted legal expenses. 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 was applied up to applicable policy limits.

Apple Valley Condemnation Proceedings

On January 7, 2016, the Town of Apple Valley (the "Town") filed a lawsuit in California state court seeking to condemn the utility assets of Liberty Utilities (Apple Valley Ranchos Water) Corp. ("Liberty Apple Valley"). On May 7, 2021, the trial court issued a Tentative Statement of Decision denying the Town'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 trial court issued the Final Statement of Decision. The trial 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 trial court. On August 2, 2022, the trial court issued a ruling awarding Liberty Apple Valley approximately $13.2 million in attorney's fees and litigation costs. The Town filed a notice of appeal of the fee award on August 22, 2022. On January 15, 2025, the California Court of Appeal issued a decision



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reversing the trial court’s finding that the Town does not have a right to take the assets of Liberty Apple Valley and reversing the award of attorney’s fees to Liberty Apple Valley. The Court of Appeal decision remands the condemnation proceedings to the trial court to determine whether to (i) allow the Town to take the water system, (ii) remand the matter to the Town for further administrative proceedings or (iii) hold a new trial and apply the appropriate burden of proof and standard of review. On February 21, 2025, Liberty Apple Valley filed a petition for review of the Court of Appeal decision with the California Supreme Court. On April 23, 2025, the California Supreme Court granted the petition for review, which is proceeding in due course before the California Supreme Court.

Lexington Gas Incident

On April 9, 2025, an explosion and fire occurred in Lexington, Missouri, destroying or damaging certain structures, including residences, served by the gas distribution system of The Empire District Gas Company. A minor died and two others suffered serious physical injuries. The National Transportation Safety Board is investigating. To date, two active lawsuits remain as well as other pre-litigation demands that have been asserted against a subsidiary of the Company and third party defendants which seek damages for personal injury and property damage. In addition, the Missouri Attorney General filed a petition for injunctive relief and civil penalties associated with the incident and on October 9, 2025, the MPSC opened an investigative docket into The Empire District Gas Company’s compliance with pipeline safety requirements. Although there can be no assurance, the Company has insurance that is currently expected to apply up to applicable policy limits for personal injury and property damage litigation and claims. The Company has currently accrued and incurred estimated losses of $152.2 million for claims related to the incident, against which recoveries through insurance of $149.0 million have been recorded, reflecting amount recovered and expected to be recovered. While the Company may incur a material loss in excess of the amount accrued, the Company cannot currently estimate the upper end of the range of reasonably possible losses that may be incurred. The estimate of losses is subject to change as additional information becomes available.

Information Security Risk

The Company relies upon its own 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. Further, the Company’s use of artificial intelligence (“AI”) also carries inherent risks related to data privacy and cybersecurity, including the potential for intended or unintended transmission of proprietary or sensitive information. As the Company operates critical infrastructure, it or its third-party vendors 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, including the increased and more sophisticated use of AI, 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 compliance obligations, and fines for breaches of such laws and regulations have increased. The



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Company may incur additional costs and require significant internal and external resources to maintain compliance, or may face significant financial penalties, in the event of a breach.

In general, the severity, volume and sophistication of targeted cyber-attacks are increasing by various actors, including state-sponsored attackers. 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 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, to the Company's hydroelectric facilities or to the electrical grid in general, and could result in a decline in the general economy and have a material adverse effect on the Company.

Technology Infrastructure Implementation Risk

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

AQN and certain of its subsidiaries have completed the implementation of an integrated customer solution platform, which includes customer billing, enterprise resource planning systems and asset management systems. The transition of operations to these new technology systems, or deficiencies in the design or implementation of these systems, could materially adversely affect the Company's operations, including its ability to monitor its business, pay its suppliers, bill its customers, and record 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 and markets 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, and 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 have resulted in incentives and programs to increase energy efficiency and reduce water and energy consumption. There may also be efforts to move to deregulation in certain of the markets in which the Company 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.



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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 Company 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.

Dispositions

For financial, strategic and other reasons, the Corporation may from time to time dispose of, or desire to dispose of, businesses or assets (in whole or in part) that it owns. 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 less proceeds than expected or liabilities to the Corporation, including as a result of any post-closing indemnities, purchase price adjustments or foreign exchange implications. In addition, the Corporation may not be able to dispose of businesses or assets that the Corporation desires or expects to sell for financial, strategic, regulatory or other 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.

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 or actions of a variety of federal, state, provincial and local governments and courts, including regulatory commissions, environmental agencies and other regulatory bodies, which laws, regulations, decisions, 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 political leadership, 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 imposition of import controls and tariffs and the power of eminent domain), court decisions, and the taking of other action by governmental, judicial or regulatory authorities, including, but not limited to, a pause, reduction or elimination of relevant federal funding, incentives, credits or programs, revocation, lapse, limitation or non-renewal of utility franchises or other rights to provide utility services to existing or new customers, lack of approval of wildfire mitigation plans which could adversely affect the Company's ability to defend against wildfire litigation or obtain sufficient wildfire liability insurance, potential complaint and administrative proceedings, potential limitations on water rights used by utilities in providing service, eminent domain of assets, termination of contracts, actions to municipalize utility service areas or limitations on utility growth and/or expansions of service areas and anti-foreign ownership sentiment and actions resulting therefrom, 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 and/or legal or regulatory decisions that could have a material impact on the Company.

Additionally, the jurisdictions in which the Company operates may be adversely affected by local, national and international political and economic developments. Such developments may include nationalization or expropriation initiatives, political instability, changes in government or governmental priorities, increased political or trade tensions between countries, legislation or policies affecting foreign ownership or investment, acts or threats of war, terrorism or other hostilities, actions taken by governments or regulatory bodies in response to such events, military actions or conflicts, and significant cybersecurity incidents originating from or directed at state or non‑state actors. Any such developments could disrupt economic conditions, impair the Company’s ability to operate or develop its assets, increase compliance or operating costs, restrict access to capital or markets, or otherwise adversely affect the Company’s business, assets, results of operations, cash flows or financial condition. As a Canadian‑domiciled company with the majority of its operations and assets located in the United States, the Corporation may also be subject to heightened risks associated with foreign ownership or control, including the enactment or enforcement of U.S. federal, state or local laws, regulations or policies that could impose additional restrictions, conditions, review requirements or limitations on the Company or its utilities, which could adversely affect the Company’s operations, growth strategies or financial performance.



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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. Liberty Utilities, the parent company for the U.S. regulated utilities under the Regulated Services Group, has an 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.

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, the Company's business mix, and risk associated with countries and/or regulatory jurisdictions in which the business operates, among other factors, may change. Such changes could require AQN to adjust its business and strategy in order to maintain its credit ratings. The Company has completed the sale of the renewable energy business (excluding hydro) and its interest in Atlantica and expects to generate nearly all of its EBITDA from the Regulated Services Group.

Capital Markets and Liquidity Risk

As at December 31, 2025, the Company and its subsidiaries had approximately $6.5 billion of long-term consolidated indebtedness. Management of the Company believes, based on its current expectations as to the Company's future performance, that the cash flow from operations, the funds available under its credit facilities, and 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, the price of the Common Shares of the Company, financial market disruptions, the failure or collapse of any financial institution, prevailing market views and 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 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, investments 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



Algonquin Power & Utilities Corp. - Management Discussion & Analysis			52

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.

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, or if 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 any 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 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 from 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.

As a result, fluctuations in interest rates 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, 2025, approximately 94% 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 90% fixed rate debt. As a result, the Company may hedge the interest rate risk on its variable interest rate borrowings from time to time.

Based on amounts outstanding as at December 31, 2025, 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 no amounts outstanding as at December 31, 2025. As a result, a 100 basis point change in the variable rate charged would not impact interest expense;

•the Long-Term Regulated Services Credit Facility is subject to a variable interest rate and had no amounts outstanding as at December 31, 2025. As a result, a 100 basis point change in the variable rate charged would not impact interest expense;

•the Regulated Services Group's commercial paper program is subject to a variable interest rate and had $337.0 million outstanding as at December 31, 2025. As a result, a 100 basis point change in the variable rate charged would impact interest expense by $3.4 million annually;

•term facilities at Suralis that are subject to variable interest rates had $78.5 million outstanding as at December 31, 2025. As a result, a 100 basis point change in the variable rate charged would impact interest expense by $0.8 million annually;

•the Bermuda Credit Facility that is subject to variable interest rates had no amounts outstanding as at December 31, 2025. As a result, a 100 basis point change in the variable rate charged would not impact interest expense.



Algonquin Power & Utilities Corp. - Management Discussion & Analysis			53

In summary, a 100 basis point change in the variable interest rate would impact the interest expense of the Company by approximately $4.2 million annually.

Foreign Currency Risk

The functional currency of a substantial majority 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 audited 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 Company is subject to income and other taxes primarily in the United States, Canada, Bermuda, and Chile. Changes in tax laws or interpretations or applications thereof, which may or may not have a retroactive effect, in the jurisdictions in which the Company does business could adversely affect the Company's results from operations, returns to shareholders, and cash flows. One or more taxing jurisdictions could seek to impose incremental or new taxes on the Company (or the Company could lose tax benefits to which it previously was entitled) pursuant to the following or otherwise:

•On July 4, 2025, the U.S. enacted the "One Big Beautiful Bill Act" (the “OBBBA”), which, among other things, significantly modifies and, in certain instances, restricts, certain energy tax provisions, including accelerating phaseout and termination of certain energy tax credits (such as those for wind and solar technologies). The OBBBA also introduced further limitations on a taxpayer’s ability to claim certain clean energy tax credits if that taxpayer is a “specified foreign entity” or a “foreign-influenced entity” or if the tax credits arise from a facility that receives an impermissible amount of assistance from a “specified foreign entity” or a “foreign-influenced entity.”

•On August 15, 2025, the Treasury Department issued Notice 2025-42. Notice 2025-42 requires owners and developers of wind and solar facilities with a maximum net output greater than 1.5 MWs to perform physical work of a significant nature (on wind and solar facilities on which construction begins on or after September 2, 2025) to qualify that facility as having begun construction prior to July 5, 2026, which, under current law, is the date by which a taxpayer must begin construction on a wind or solar facility for that facility to qualify for federal clean energy tax credits. If the Company does not meet this requirement in respect of these wind and solar facilities, along with other complex rules necessary to claim federal income tax credits in respect of these facilities, the Company may not receive certain economic benefits to which it otherwise would be entitled (including federal income tax credits), resulting in adverse effects on the Corporation, its operations, and returns to shareholders.

The Company cannot predict the ultimate effect on the Company's business of the OBBBA or of other current or future executive orders or other related legislative or regulatory initiatives. The Corporation cannot provide assurance that the Canada Revenue Agency, the U.S. 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, the cost amount of the Corporation's depreciable properties, and energy-related tax credits claimed by the Company. A successful challenge (including one with retroactive effect) by an applicable taxation authority regarding such tax positions could adversely affect the results of operations and financial position of the Company.

The Company benefits from federal tax credits and other tax incentives with respect to the development and operation of power generation and storage facilities in the United States, including its remaining investments in the operating facilities associated with the Renewables Sale. Recent political developments in the U.S. (including the enactment of the OBBBA and the issuance of Notice 2025-42) have introduced significant uncertainty with respect to these federal tax incentives. The Company’s investments in certain tax equity financing and monetization transactions with respect to projects in the United States could be affected adversely (including with retroactive effect) if there are changes in U.S. tax laws.



Algonquin Power & Utilities Corp. - Management Discussion & Analysis			54

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 Offtake Contracts (as defined below), 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.

AQN’s key businesses includes Regulated Services Group, Hydro Group, and Corporate Group. The company’s revenue 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 $90.6 million which is spread over approximately 583,000 customer connections, resulting in an average outstanding balance of approximately $155 dollars per customer connection.

The natural gas distribution systems accounts receivable balances related to the natural gas utilities total $165.1 million, while electric distribution systems accounts receivable balances related to the electric utilities total $161.5 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 $437 and $519 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 long-term power purchase agreement ("PPA"), unit contingent or fixed-shape offtake contracts or other energy offtake or hedging arrangements (together with PPAs, "Offtake Contracts") with the Company is unable to perform, the Hydro Group may be unable to replace the contract on comparable terms, in which case sales of power 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 on the Hydro Group. 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 Company. 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
A substantial portion of the output of the Hydro Group’s power generation facilities is sold under Offtake Contracts, under which a purchaser is obligated to purchase all or a specified portion of the output of the applicable facility and (in some cases) associated renewable energy credits. The breach, termination or expiry of any such Offtake Contract, unless replaced or renewed on equally favourable terms, could adversely affect the Company’s results of operations and cash flows and increase the Company’s exposure to risks of price fluctuations in the wholesale power market.

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.

Commodity Price Risk

The Regulated Services Group is exposed to energy and natural gas price risks at its electric and natural gas systems.

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 CalPeco to seek authority for a potential adjustment to its 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 or community aggregators. For those customers who do not choose their own competitive energy supplier or opt out of community power aggregation programs, Granite State Electric System provides a



Algonquin Power & Utilities Corp. - Management Discussion & Analysis			55

Default Service offering to each class of customers through two separate processes. First is a competitive bidding process that is undertaken semi-annually for 50 percent of the Default Service load for customers in rate classes included in the Small Customer Group, which includes residential and small commercial customers. The winning bidder is obligated to provide a full requirements service based on the actual needs of those 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 full-requirements supply by 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. Granite State Electric System is only committed to the winning Default Service supplier(s) after approval by the NHPUC, and accordingly, the risk associated with entering into these contracts is mitigated. Under the second process, which applies for the Default Service load for the remaining 50 percent of the Small Customer Group and 100 percent of the Large Customer Group, which includes large commercial customers, Granite State Electric System is required by the NHPUC to self-supply by taking those portions of the Default Service load to the ISO New England market and purchasing energy and other requirements on a daily basis, optimizing between the Day-Ahead and Real-Time markets in accordance with instructions and approval received from the NHPUC. The costs incurred through this market process are also pass-through costs that are reconciled and recovered as part of the same semi-annual process described above, similarly mitigating commodity risk. Cost recovery of both processes is subject to Commission approval.

The EnergyNorth Natural Gas System purchases 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 periodically approved by the NHPUC through Least Cost Integrated Resource Plan filings which typically are filed every four years (the timing of the LCIRP process is currently in flux due to recent statutory changes). In addition, the 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. 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 hedges a portion of its normal winter period purchases under a NHPUC approved hedging program. All costs associated with the hedging program are allowed to be a pass-through to customers as part of the COG filing and the approved rates in said filing. Should commodity prices change relative to the initial annual COG rate, the EnergyNorth Natural Gas System has the right to automatically increase its COG rates going forward up to 25% and decrease with no limit in order to minimize any under or over collection of its natural gas costs. In addition, any under and over 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/monthly Purchase Gas Adjustment ("PGA") filings and approval process. The Midstates Gas Systems serves customers in Missouri, Illinois and Iowa and establishes rates for its customers within the PGA filing in each state and these rates are designed to fully recover its anticipated transportation, storage and commodity costs. In order to minimize commodity price fluctuations, the Midstates Gas System has implemented a commodity hedging program, consistent with 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 forecasted costs relative to the amounts assumed in the Gas Supply Plan , minimizing any under or over collection of its natural gas costs.



Algonquin Power & Utilities Corp. - Management Discussion & Analysis			56

The St. Lawrence Gas System purchases pipeline capacity, storage and commodity from a variety of counterparties. The St. Lawrence Gas System's portfolio of assets and its planning and forecasting methodology are periodically approved by the New York Public Service Commission ("NYPSC") through annual filings of Gas Purchase and Winter Supply Plans. In addition, St. Lawrence Gas files with the NYPSC for recovery of its transportation and commodity costs via the Gas Average Cost ("GAC") filing. These rates are designed to fully recover its anticipated transportation and commodity costs. In order to minimize commodity price fluctuations, St. Lawrence Gas hedges a portion of its normal winter period purchases as part of its reviewed Winter Supply Plan. All costs associated with hedging are allowed to be a pass-through to customers as part of the GAC filing and the approved rates in said filing. Should commodity prices change relative to the initial annual GAC rate, St. Lawrence Gas is able to carry forward to the next year's corresponding GAC period (i.e. winter to winter and summer to summer).

The Liberty Utility Gas (“LUG”) Standard Offering in New Brunswick purchases pipeline capacity and commodity from a variety of counterparties, and files with the New Brunswick Energy and Utilities Board ("NBEUB") monthly as required for natural gas purchase and sales activity regulations. The Natural Gas Marketers Regulation in New Brunswick establishes rules governing LUG designed to fully recover its anticipated transportation and commodity costs. In order to minimize commodity price fluctuations, LUG price is set based on the forward looking 12 month average expected cost filed by New Brunswick Gas and audited by the NBEUB annually. LUG does not hedge any of its commodity purchases during the year. All costs related to natural gas purchase and sale are passed through to customers 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 forecast assumed in the LUG filings, minimizing any under or over collection of its natural gas costs.

The Empire District Electric System's natural gas procurement program for electrical generation is designed to manage costs to mitigate volatile natural gas prices. The Empire District 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 and Light Fuel Oil (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.



Algonquin Power & Utilities Corp. - Management Discussion & Analysis

QUARTERLY FINANCIAL INFORMATION

The following is a summary of unaudited quarterly financial information for each of the eight most recent quarters, the most recent of which ended December 31, 2025:


(all dollar amounts in $ millions except per share information)	1st Quarter 2025		2nd Quarter 2025		3rd Quarter 2025		4th Quarter 2025
Revenue	$	692.4	$	527.8	$	582.7	$	630.7

Net earnings	94.2		21.5		36.2		18.4
Net earnings from continuing operations	92.8		14.8		71.0		29.4
Net earnings (loss) from discontinued operations	1.4		6.7		(34.8)		(11.0)
Net earnings per share	0.12		0.03		0.05		0.02
Net earnings per share from continuing operations	0.12		0.02		0.09		0.04
Net earnings (loss) per share from discontinued operations	—		0.01		(0.04)		(0.01)
Diluted net earnings per share	0.12		0.03		0.05		0.02
Adjusted Net Earnings1	109.0		33.6		69.0		47.2
Adjusted Net Earnings per common share1	0.14		0.04		0.09		0.06
EBIT1	168.7		74.2		157.4		93.2
Total assets3	13,663.3		13,693.4		13,788.4		14,136.2
Long-term debt2,3	6,322.0		6,328.8		6,434.6		6,532.9
Dividends declared per common share	$	0.07	$	0.07	$	0.07	$	0.07
	1st Quarter 2024		2nd Quarter 2024		3rd Quarter 2024		4th Quarter 2024
Revenue	$	646.2	$	515.3	$	573.2	$	584.8

Net earnings (loss)	(91.5)		198.0		(1,308.4)		(189.1)

Net earnings (loss) from continuing operations	(59.2)		177.4		46.8		(110.2)
Net earnings (loss) from discontinued operations	(32.3)		20.6		(1,355.2)		(78.9)
Net earnings (loss) per share	(0.13)		0.28		(1.71)		(0.25)
Net earnings (loss) per share from continuing operations	(0.09)		0.26		0.06		(0.14)
Net earnings (loss) per share from discontinued operations	(0.04)		0.02		(1.77)		(0.10)
Diluted net earnings (loss) per share	(0.13)		0.28		(1.71)		(0.25)
Adjusted Net Earnings1	77.4		39.5		62.2		42.5
Adjusted Net Earnings per common share1	0.11		0.06		0.08		0.06
EBIT1	18.6		275.3		131.1		115.8
Total assets3	18,307.8		18,866.4		17,788.6		16,961.7
Long-term debt2,3	9,089.9		8,292.9		8,725.0		8,047.5
Dividends declared per common share	$	0.11	$	0.11	$	0.07	$	0.07


1			See Caution Concerning Non-GAAP Measures.
2			Includes current portion of long-term debt and long-term debt.
3			Includes discontinued operations

Quarterly revenues have fluctuated between $515.3 million and $692.4 million over the prior two year period. A number of factors impact quarterly results, including acquisitions, dispositions, seasonal fluctuations and customer rates. 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 (loss) attributable to common shareholders have fluctuated between a loss of $1,308.4 million and earnings of $198.0 million over the prior two year period. Earnings have been impacted by non-cash factors such as impairment upon classification of the renewable energy group (excluding hydro) as held for sale, deferred tax recovery and expense, property, plant and equipment and mark-to-market gains and losses on financial instruments.



Algonquin Power & Utilities Corp. - Management Discussion & Analysis			58

DISCLOSURE CONTROLS AND PROCEDURES

AQN's management carried out an evaluation as of December 31, 2025, 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, 2025, 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, 2025, based on the framework established in Internal Control - Integrated Framework (2013) issued by the Committee of Sponsoring Organizations of the Treadway Commission. 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, 2025 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, 2025, 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.

CRITICAL ACCOUNTING ESTIMATES AND POLICIES

AQN prepared its audited consolidated financial statements in accordance with U.S. GAAP. The preparation of the audited 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 audited 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.

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 over which assets are depreciated.



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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 energy pricing operational or financial performance, unexpected outcome from rate orders, natural disasters, 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 2025 and 2024, management assessed qualitative and quantitative factors for each of the reporting units that were allocated goodwill. No goodwill impairment provision was required.

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.

With respect to the Company's Canadian deferred tax assets, management continues to conclude that it is not probable that most of the benefit of these assets will be realized. In January 2025, the Company completed the Renewables Sale, which resulted in a capital loss for Canadian tax purposes. Following the Renewables Sale, the Company has limited Canadian entities that are operationally profitable. Management has evaluated all available positive and negative evidence applicable to the remaining entities in Canada and has concluded that it is not probable that the Canadian businesses will earn sufficient taxable profit to allow for the full utilization of available tax attributes prior to their expiry. A valuation allowance continues to be recorded against the majority of the Canadian deferred tax assets.

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.



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Derivatives

AQN uses derivative instruments to manage exposure to changes in commodity prices, foreign exchange rates, and interest rates. Management's judgment is required to determine if a transaction meets the definition of a derivative and, if it does, whether the normal purchases and sales exception applies or whether individual transactions qualify for hedge accounting treatment. Management's judgment is also required to determine the fair value of derivative transactions. AQN determines the fair value of derivative instruments based on forward market prices in active markets obtained from external parties adjusted for nonperformance risk. A significant change in estimate could affect AQN's results of operations if the hedging relationship was considered no longer effective.

Pension and Post-employment Benefits

The obligations and related costs of defined benefit pension and other post-employment benefit plans ("OPEB") 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, 2025 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, 2025 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 2025 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.


	2025 Pension Plans				2025 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		(52.8)		(2.7)		(21.6)		(3.2)
1% decrease		62.0		2.1		26.2		3.1

Future compensation rate
1% increase		1.0		1.0		—		—
1% decrease		(1.5)		(1.0)		—		—

Expected return on plan assets
1% increase		—		(4.6)		—		(1.6)
1% decrease		—		4.6		—		1.6

Health care trend
1% increase		—		—		24.5		3.2
1% decrease		—		—		(20.3)		(3.2)



Algonquin Power & Utilities Corp. - Management Discussion & Analysis