Exhibit 99.3

Management Discussion & Analysis

(All monetary amounts are in thousands of Canadian dollars, except per share amounts or where otherwise noted.)

Management of Algonquin Power & Utilities Corp. (“APUC” or the “Company” or the “Corporation”) has prepared the following discussion and analysis to provide information to assist its shareholders’ understanding of the financial results for the three and twelve months ended December 31, 2017. This Management Discussion & Analysis (“MD&A”) should be read in conjunction with APUC’s consolidated financial statements for the years ended December 31, 2017 and 2016. This material is available on SEDAR at www.sedar.com and on the APUC website at www.AlgonquinPowerandUtilities.com. Additional information about APUC, including the most recent Annual Information Form (“AIF”) can be found on SEDAR at www.sedar.com.

Unless otherwise indicated, financial information provided for the years ended December 31, 2017 and 2016 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.

This MD&A is based on information available to management as of March 7, 2018.

Contents

Caution Concerning Forward-Looking Statements, Forward-Looking Information and non-GAAP Measures	2
Overview and Business Strategy	5
2017 Major Highlights	6
2017 Fourth Quarter Results From Operations	9
2017 Annual Results From Operations	11
2017 Adjusted EBITDA Summary	14
Liberty Power Group	15
Liberty Utilities Group	20
Corporate Development Activities	29
APUC: Corporate and Other Expenses	32
Non-GAAP Financial Measures	35
Summary of Property, Plant, and Equipment Expenditures	37
Liquidity and Capital Reserves	39
Share-Based Compensation Plans	42
Management of Capital Structure	43
Related Party Transactions	43
Enterprise Risk Management	44
Quarterly Financial Information	55
Disclosure Controls and Internal Controls Over Financial Reporting	56
Critical Accounting Estimates and Policies	57

Caution Concerning Forward-looking Statements, Forward-looking Information and non-GAAP Measures

Forward-looking Statements and Forward-Looking Information

This document may contain statements that constitute "forward-looking statements" or "forward-looking information" within the meaning of applicable securities legislation (collectively, “forward-looking information”). The words “anticipates”, “believes”, “budget”, “could”, “estimates”, “expects”, “forecasts”, “intends”, “may”, “might”, “plans”, “projects”, “schedule”, “should”, “will”, “would” 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 are not limited to, statements relating to: expected future growth and results of operations; liquidity, capital resources and operational requirements; rate cases, including resulting decisions and rates and expected impacts and timing; sources of funding, including adequacy and availability of credit facilities, debt maturation and future borrowings; ongoing and planned acquisitions, projects and initiatives, including expectations regarding costs, financing, results and completion dates; expectations regarding the cost of operations, capital spending and maintenance, and the variability of those costs; expected future capital investments, including expected timing, investment plans and impacts; expectations regarding generation availability, capacity and production; expectations regarding the outcome of existing or potential legal and contractual claims and disputes; expectations regarding the ability to access the capital market on reasonable terms; strategy and goals; contractual obligations and other commercial commitments; environmental liabilities; dividends to shareholders; expectations regarding the impact of tax reforms; credit ratings; anticipated growth and emerging opportunities in APUC’s target markets; accounting estimates; interest rates; currency exchange rates; and commodity prices. All forward-looking information is given pursuant to the “safe harbor” 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 on commercially reasonable terms and the stability of credit ratings of the Corporation and its subsidiaries; the absence of unexpected material liabilities or uninsured losses; the continued availability of commodity supplies and stability of commodity prices; the absence of sustained interest rate increases or significant currency exchange rate fluctuations; the absence of significant operational disruptions or liability due to natural disasters or catastrophic events; 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 and market conditions; the successful and timely development and construction of new projects; the absence of material capital project or financing cost overruns; sufficient liquidity and capital resources; the continuation of observed weather patterns and trends; the absence of significant counterparty defaults; the continued competitiveness of electricity pricing when compared with alternative sources of energy; the realization of the anticipated benefits of the Corporation’s acquisitions and joint ventures; the absence of a material change in political conditions or public policies and directions by governments materially negatively affecting the Corporation; the ability to obtain and maintain licenses and permits; the absence of a material decrease 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 cyber security; favourable relations with external stakeholders; and favourable labour relations.

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 and market conditions; changes in customer energy usage patterns and energy demand; global climate change; the incurrence of environmental liabilities; natural disasters and other catastrophic events; the failure of information technology infrastructure and cybersecurity; 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, 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; critical equipment breakdown or failure; terrorist attacks; fluctuations in commodity 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; sustained increases in interest rates; currency exchange rate fluctuations; restricted financial flexibility due to covenants in existing credit agreements; an inability to refinance maturing debt on commercially reasonable 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 to health and safety laws, regulations or permit requirements; failure to comply with and/or changes to environmental laws, regulations and other standards; compliance with new foreign laws or regulations; failure to identify attractive acquisition or development candidates necessary to pursue the Corporation’s growth strategy; delays and cost overruns in the design and construction of projects; loss of key customers; failure to realize the

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

anticipated benefits of acquisitions or joint ventures; Atlantica or the Corporation’s joint venture with Abengoa acting in a manner contrary to the Corporation’s best interests; facilities being condemned or otherwise taken by governmental entities; increased external stakeholder activism adverse to the Corporation’s interests; and fluctuations in the price and liquidity of the Corporation’s Common Shares. 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” and in the Corporation's AIF.

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 law. All forward-looking information contained herein is qualified by these cautionary statements.

Non-GAAP Financial Measures

The terms “Adjusted Net Earnings”, “Adjusted Earnings Before Interest, Taxes, Depreciation and Amortization” (“Adjusted EBITDA”), “Adjusted Funds from Operations”, "Net Energy Sales", "Net Utility Sales" and "Divisional Operating Profit" are used throughout this MD&A. The terms “Adjusted Net Earnings”, “Adjusted Funds from Operations”, "Adjusted EBITDA", "Net Energy Sales", "Net Utility Sales" and "Divisional Operating Profit" are not recognized measures under U.S. GAAP. There is no standardized measure of “Adjusted Net Earnings”, "Adjusted EBITDA", “Adjusted Funds from Operations”, "Net Energy Sales", "Net Utility Sales", and "Divisional Operating Profit"; consequently, APUC’s method of calculating these measures may differ from methods used by other companies and therefore may not be comparable to similar measures presented by other companies. A calculation and analysis of “Adjusted Net Earnings”, "Adjusted EBITDA", “Adjusted Funds from Operations”, "Net Energy Sales", "Net Utility Sales", and "Divisional Operating Profit" can be found throughout this MD&A.

Adjusted EBITDA

EBITDA is a non-GAAP measure used by many investors to compare companies on the basis of ability to generate cash from operations. APUC uses these calculations to monitor the amount of cash generated by APUC as compared to the amount of dividends paid by APUC. APUC uses Adjusted EBITDA to assess the operating performance of APUC without the effects of (as applicable): depreciation and amortization expense, income tax expense or recoveries, acquisition costs, litigation expenses, interest expense, gain or loss on derivative financial instruments, write down of intangibles and property, plant and equipment, earnings attributable to non-controlling interests and gain or loss on foreign exchange, earnings or loss from discontinued operations and other typically non-recurring items. APUC adjusts for these factors as they may be non-cash, unusual in nature and are not factors used by management for evaluating the operating performance of the Company. APUC believes that presentation of this measure will enhance an investor’s understanding of APUC’s operating performance. Adjusted EBITDA is not intended to be representative of cash provided by operating activities or results of operations determined in accordance with U.S. GAAP.

Adjusted Net Earnings

Adjusted Net Earnings is a non-GAAP measure used by many investors to compare net earnings from operations without the effects of certain volatile primarily non-cash items that generally have no current economic impact or items such as acquisition expenses or litigation expenses that are viewed as not directly related to a company’s operating performance. APUC 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 costs, one-time costs of arranging tax equity financing, litigation expenses and write down of intangibles and property, plant and equipment, earnings or loss from discontinued operations, unrealized mark-to-market revaluation impacts, and other typically non-recurring items as these are not reflective of the performance of the underlying business of APUC. For 2017, the one-time impact of the revaluation of U.S. non-regulated net deferred income tax assets as a result of the U.S. federal corporate income tax rate reduction from 35% to 21% enacted in December 2017 is adjusted as it is also considered a non-recurring item not reflective of the performance of the underlying business of APUC. APUC 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. It is not intended to be representative of net earnings or loss determined in accordance with U.S. GAAP, which can be impacted positively or negatively by these items.

Adjusted Funds from Operations

Adjusted Funds from Operations is a non-GAAP measure used by investors to compare cash flows from operating activities without the effects of certain volatile items that generally have no current economic impact or items such as acquisition expenses that are viewed as not directly related to a company’s operating performance. APUC uses Adjusted Funds from Operations to assess its performance without the effects of (as applicable): changes in working capital balances, acquisition

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

expenses, litigation expenses, cash provided by or used in discontinued operations and other typically non-recurring items affecting cash from operations as these are not reflective of the long-term performance of the underlying businesses of APUC. APUC believes that analysis and presentation of funds from operations on this basis will enhance an investor’s understanding of the operating performance of its businesses. It is not intended to be representative of cash flows from operating activities as determined in accordance with GAAP, which can be impacted positively or negatively by these items.

Net Energy Sales

Net Energy Sales is a non-GAAP measure used by investors to identify revenue after commodity costs used to generate revenue where such revenue generally increases or decreases in response to increases or decreases in the cost of the commodity used to produce that revenue. APUC uses Net Energy Sales to assess its revenues without the effects of fluctuating commodity costs as such costs are predominantly passed through either directly or indirectly in the rates that are charged to customers. APUC believes that analysis and presentation of Net Energy Sales on this basis will enhance an investor’s understanding of the revenue generation of its businesses. It is not intended to be representative of revenue as determined in accordance with U.S. GAAP.

Net Utility Sales

Net Utility Sales is a non-GAAP measure used by investors to identify utility revenue after commodity costs, either natural gas or electricity, where these commodity costs are generally included as a pass through in rates to its utility customers. APUC 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. APUC believes that analysis and presentation of Net Utility Sales on this basis will enhance an investor’s understanding of the revenue generation of its utility businesses. It is not intended to be representative of revenue as determined in accordance with U.S. GAAP.

Divisional Operating Profit

Divisional Operating Profit is a non-GAAP measure. APUC uses Divisional Operating Profit to assess the operating performance of its business groups without the effects of (as applicable): depreciation and amortization expense, corporate administrative expenses, income tax expense or recoveries, acquisition costs, litigation expenses, interest expense, gain or loss on derivative financial instruments, write down of intangibles and property, plant and equipment, and gain or loss on foreign exchange, earnings or loss from discontinued operations and other typically non-recurring items. APUC adjusts for these factors as they may be non-cash, unusual in nature and are not factors used by management for evaluating the operating performance of the divisional units. Divisional Operating Profit is calculated inclusive of Hypothetical Liquidation at Book Value (“HLBV”) income, which represents the value of net tax attributes earned in the period from electricity generated by certain of its U.S. wind power and U.S. solar generation facilities. APUC believes that presentation of this measure will enhance an investor’s understanding of APUC’s divisional operating performance. Divisional Operating Profit is not intended to be representative of cash provided by operating activities or results of operations determined in accordance with U.S. GAAP.

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

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

Overview and Business Strategy

APUC is incorporated under the Canada Business Corporations Act. APUC owns and operates a diversified portfolio of regulated and non-regulated generation, distribution, and transmission utility assets which are expected to deliver predictable earnings and cash flows. APUC seeks to maximize total shareholder value through real per share growth in earnings and cash flows to support a growing dividend and share price appreciation.

APUC’s current quarterly dividend to shareholders is U.S. $0.1165 per common share or U.S. $0.4660 per common share per annum. Based on exchange rates as at February 28, 2018, the quarterly dividend is equivalent to Cdn $0.1492 per common share or Cdn $0.5969 per common share per annum. APUC believes its annual dividend payout allows for both an immediate return on investment for shareholders and retention of sufficient cash within APUC to fund growth opportunities. Changes in the level of dividends paid by APUC are at the discretion of the APUC Board of Directors (the “Board”), with dividend levels being reviewed periodically by the Board in the context of cash available for distribution and earnings together with an assessment of the growth prospects available to APUC. APUC strives to achieve its results in the context of a moderate risk profile consistent with top-quartile North American power and utility operations.

APUC's operations are organized across two primary North American business units consisting of: the Liberty Power Group, which owns and operates a diversified portfolio of non-regulated renewable and thermal electric generation assets; and the Liberty Utilities Group. which owns and operates a portfolio of regulated electric, natural gas, water distribution and wastewater collection utility systems, and transmission operations.

Liberty Power Group

The Liberty Power Group generates and sells electrical energy produced by its diverse portfolio of non-regulated renewable power generation and clean power generation facilities located across North America. The Liberty Power Group seeks to deliver continuing growth through development of new greenfield power generation projects and accretive acquisitions of additional electrical energy generation facilities.

The Liberty Power Group owns or has interests in hydroelectric, wind, solar, and thermal facilities with a combined generating capacity of approximately 120 MW, 1,050 MW, 40 MW, and 335 MW, respectively. Approximately 87% of the electrical output from the hydroelectric, wind, and solar generating facilities is sold pursuant to long term contractual arrangements which as of December 31, 2017 had a production-weighted average remaining contract life of approximately 15 years.

Liberty Utilities Group

The Liberty Utilities Group operates a diversified portfolio of regulated utility systems throughout the United States serving approximately 762,000 customers. The Liberty Utilities Group provides safe, high quality, and reliable services to its customers and seeks to deliver stable and predictable earnings to APUC. In addition to encouraging and supporting organic growth within its service territories, the Liberty Utilities Group seeks to deliver continued growth in earnings through accretive acquisition of additional utility systems.

The Liberty Utilities Group's regulated electrical distribution utility systems and related generation assets are located in the States of California, New Hampshire, Missouri, Kansas, Oklahoma, and Arkansas. The electric utility systems in total serve approximately 265,000 electric connections and operate a fleet of generation assets with a net capacity of 1,424 MW.

The Liberty Utilities Group's regulated natural gas distribution utility systems are located in the States of Georgia, Illinois, Iowa, Massachusetts, New Hampshire and Missouri serving approximately 337,000 natural gas connections.

The Liberty Utilities Group's regulated water distribution and wastewater collection utility systems are located in the States of Arizona, Arkansas, California, Illinois, Missouri, and Texas which together serve approximately 160,000 connections.

Corporate Development

The Company is presently developing a portfolio of renewable power generation projects that, when constructed, will add approximately 361 MW of generation capacity from wind and solar powered generating facilities and, that when completed and on-line, will have a production-weighted average contract life of approximately 22 years.

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2017 Major Highlights

Corporate Highlights

Strong Year of Operating Results

APUC recorded a strong twelve months of operating results relative to the same period last year.

(all dollar amounts in $ millions except per share information)	Twelve Months Ended December 31
	2017	2016	Change
Net earnings attributable to shareholders	$193.1	$130.9	48%
Adjusted Net Earnings	$292.1	$161.6	81%
Adjusted EBITDA	$883.4	$476.9	85%
Net earnings per common share	$0.48	$0.44	9%
Adjusted Net Earnings per common share	$0.74	$0.57	30%

Declaration of Canadian Equivalent 2018 First Quarter Dividend of Cdn $0.1492 (U.S. $0.1165) per Common Share

On March 1, 2018, APUC announced that the Board of Directors of APUC declared a first quarter 2018 dividend of U.S. $0.1165 per common share payable on April 13, 2018 to shareholders of record on March 29, 2018. Based on the Bank of Canada exchange rate on the declaration date, the Canadian dollar equivalent for the first quarter 2018 dividend is set at Cdn $0.1492 per common share.

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

	Q2 2017	Q3 2017	Q4 2017	Q1 2018	Total
U.S. dollar dividend	$0.1165	$0.1165	$0.1165	$0.1165	$0.4660
Canadian dollar equivalent	$0.1593	$0.1480	$0.1478	$0.1492	$0.6043

Investment in Joint Venture with Abengoa and Purchase of 25% Interest in Atlantica Yield plc

On November 1, 2017, APUC entered into an agreement to create a joint venture, Abengoa-Algonquin Global Energy Solutions ("AAGES"), with Seville, Spain-based Abengoa, S.A (MCE: ABG) ("Abengoa") to identify, develop, and construct clean energy and water infrastructure assets with a global focus. Concurrently with the creation of the AAGES joint venture, APUC entered into a definitive agreement to purchase from Abengoa a 25% equity interest in Atlantica Yield plc ("Atlantica") for a total purchase price of approximately U.S. $608 million, based on a price of U.S. $24.25 per ordinary share of Atlantica, plus a contingent payment of up to U.S. $0.60 per share payable two years after closing, subject to certain conditions. The transaction is expected to close sometime in the first quarter of 2018.

Completion of The Empire District Electric Company Acquisition and Financing

On January 1, 2017, APUC's wholly-owned regulated utility business successfully completed its acquisition of The Empire District Electric Company ("Empire") for an aggregate purchase price of approximately U.S. $2.414 billion including the assumption of approximately U.S. $0.9 billion of debt ("Empire Acquisition").

Empire is a Joplin, Missouri-based vertically integrated, regulated electric, gas and water utility with approximately 1.4 GW of generating capacity serving approximately 221,000 customers in Missouri, Kansas, Oklahoma, and Arkansas.

$1.15 Billion Bought Deal Offering of Convertible Unsecured Subordinated Debentures Represented by Instalment Receipts

In the first quarter of 2016, in connection with the Empire Acquisition, APUC and its direct wholly-owned subsidiary, Liberty Utilities (Canada) Corp., entered into an agreement with a syndicate of underwriters under which the underwriters agreed to buy, on a bought deal basis, $1.15 billion aggregate principal amount of 5.00% convertible unsecured subordinated debentures ("Debentures") of APUC (the "Debenture Offering").

Following the closing of the Empire Acquisition, the final instalment date was established as February 2, 2017, at which time APUC received the final instalment payment. The proceeds were used to repay a portion of APUC's bank facility drawn at closing of the Empire Acquisition ("Acquisition Facility"). As at March 6, 2018, approximately 99.9% of the Debentures have been converted into common shares of APUC, with APUC issuing approximately 108,384,716 common shares as a result of the conversion.

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

U.S. $750 Million Private Placement Offering

On March 24, 2017, the Liberty Utilities Group's financing entity issued U.S. $750 million of senior unsecured notes on a private placement basis to 29 institutional investors in the U.S. and Canada. The notes are of varying maturities from 3 to 30 years with a weighted average life of approximately 15 years and an effective interest rate of 3.6% (inclusive of interest rate hedges).

Corporate Financings Completed:

$576 Million Bought Deal Offering of Common Shares

On November 10, 2017, APUC announced that it closed a bought deal offering announced on November 1, 2017, including the exercise in full of the underwriters' over-allotment option. As a result, a total of 43,470,000 common shares of APUC were sold at a price of $13.25 per share for gross proceeds of approximately $576.0 million.

U.S. Tax Reform

On December 22, 2017, the Tax Cuts and Jobs Act ("U.S. Tax Reform") was signed into law in the U.S., which, amongst other significant changes, reduced the U.S. federal corporate tax rate from 35% to 21%.

As a result of U.S. Tax Reform, the Company is required to revalue its U.S. deferred income tax assets and liabilities based on the new tax rate. This revaluation resulted in a one time non-cash accounting charge of $22.4 million to be recorded in the Company's consolidated statement of operations for the quarter and year ended December 31, 2017.

The Company expects that the effects of U.S. Tax Reform in 2018 will be neutral to slightly positive to EPS and approximately 2%-3% negative to 2018 EBITDA, which is within the planning parameters that APUC establishes for normal variability in its business cycle from wind, hydrology and weather.

The Company expects its effective tax rate in 2018 on its consolidated worldwide net income to be below 20%.

Additional detail on U.S. Tax Reform can be found later in this document under Corporate and Other expenses.

Change to U.S. Dollar Reporting

Effective the first quarter of 2018, APUC's interim and annual consolidated financial statements will be reported in U.S. dollars.

Over 90% of APUC's consolidated revenue, EBITDA and assets are derived from operations in the United States. In addition, APUC's dividend is denominated in U.S. dollars and the Company's common shares are listed on the New York Stock Exchange. The Company believes that the change in reporting to U.S. dollars will provide improved information to investors and allow for better assessment of its results without the effects of the change in currency on 90% of its operations.

Liberty Power Group Highlights

Completion of the Deerfield Wind Project

On February 21, 2017, the Deerfield Wind Facility achieved commercial operations ("COD"). The project consists of a 150 MW wind generating facility located in central Michigan. On May 10, 2017, tax equity financing of approximately U.S. $166.6 million was completed. The Deerfield Wind Facility is the Liberty Power Group's tenth wind generating facility and consists of 44 Vestas V110-2.0 wind turbines and 28 Vestas V110-2.2 turbines and is expected to generate 555.2 GW-hrs annually. The project has a 20 year Power Purchase Agreement ("PPA") with a local electric distribution utility serving approximately 260,000 customers in Michigan.

Completion of the Bakersfield II Solar Project

On January 11, 2017, the Liberty Power Group achieved COD on the 10 MWac solar generating facility located in Kern County, California (the "Bakersfield II Solar Facility"). On February 28, 2017, tax equity financing of approximately U.S. $12.3 million was completed. The Bakersfield II Solar Facility is the Liberty Power Group's third solar generating facility and is comprised of approximately 38,640 solar panels located on 64 acres of land. The project is expected to generate 24.2 GW-hrs of energy annually. The project has a 20 year PPA with a large investment grade electric utility in California.

Issuance of $300 million Senior Unsecured Debentures

On January 17, 2017, the Liberty Power Group issued $300.0 million of senior unsecured debentures bearing interest at 4.09% and with a maturity date of February 17, 2027. The debentures were sold at a price of $99.929 per $100.00 principal amount. Concurrent with the offering, the Liberty Power Group entered into a cross currency swap, coterminous with the debentures, to economically convert the Canadian dollar denominated offering into U.S. dollars.

The net proceeds were used to partially finance the Odell Wind, Deerfield Wind and Bakersfield II Solar projects.

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

Liberty Utilities Group Highlights

Successful Rate Case Outcomes

A core strategy of the Liberty Utilities Group is to ensure an appropriate return is earned on the rate base at its various utility systems. During 2017, the Liberty Utilities Group successfully completed several rate cases representing a cumulative annualized revenue increase of approximately U.S. $20.4 million. The Liberty Utilities Group has pending rate case filings in progress that are expected to be completed in 2018 that if successful will represent an increase in rates in the amount of U.S. $44.9 million.

Application to Develop up to 800 MW of Wind in the Midwest

On October 31, 2017, Empire announced a proposed plan to phase out its Asbury coal generation facility and expand its wind resources with the development of up to an additional 800 MW of strategically located wind generation in or near its service territory by the end of 2020. The plan projects cost savings for customers of U.S. $172.0 - U.S. $325.0 million over a twenty-year period. Empire filed a request for approval of the wind expansion initiative with regulators in Missouri, Kansas, Oklahoma, and Arkansas, and the project is subject to their respective review. Orders from the various jurisdictions are anticipated by June 2018.

Granite Bridge Project

On December 4, 2017, the Liberty Utilities Group announced plans for the development of a new infrastructure project designed to bring additional natural gas supply to New Hampshire’s residents and businesses. The project, called Granite Bridge, would bring natural gas from existing infrastructure located in New Hampshire’s Seacoast region to the central part of the state through an underground pipeline. The proposed Granite Bridge project is estimated to cost between U.S. $320.0 million and U.S. $360 million and would connect the existing Portland Natural Gas Transmission System and Maritimes and Northeast Pipeline facilities in Stratham with the existing Tennessee Gas Pipeline facilities in Manchester. The Granite Bridge project also includes a proposed Liquefied Natural Gas storage facility capable of storing up to two billion cubic feet of natural gas. The final project will be subject to approval from regulatory authorities.

Acquisition of the St. Lawrence Gas Company, Inc.

On August 31, 2017, the Company entered into a definitive agreement to acquire St. Lawrence Gas Company, Inc. ("SLG"). SLG is a rate-regulated natural gas distribution utility serving approximately 16,000 customers in northern New York State. The total purchase price for the transaction is U.S. $70.0 million, less total third-party debt of SLG outstanding at closing, and subject to customary working capital adjustments. Closing of the transaction remains subject to regulatory approval and other closing conditions and is expected to occur in late 2018 or early 2019.

Acquisition of the Perris Water Distribution System

On August 10, 2017, the Company’s board approved the acquisition of two water distribution systems serving approximately 4,000 customers in the City of Perris, California.  The anticipated purchase price of U.S. $11.5 million is expected to be established as rate base during the regulatory approval process.  Liberty Utilities was the successful bidder in the city’s request for proposal process and in July 2017 the Perris City council voted to approve the sale to Liberty Utilities.  The City of Perris residents voted to approve the sale on November 7, 2017. Liberty Utilities expects to file the advice letter to acquire the water utility with the California Public Utility Commission ("CPUC") in Q1 2018, with approval expected in late 2018.

Completion of the Luning Solar Facility

On February 15, 2017, the Liberty Utilities Group acquired control of a 50 MWac solar generating facility located in Mineral County, Nevada for approximately U.S. $110.9 million. The facility is comprised of approximately 204,784 solar panels located on 584 acres of land. The facility is expected to generate 144.6 GW-hrs of energy annually. On February 17, 2017, tax equity financing of approximately U.S. $39.0 million was completed. The net capital cost of the facility is included in the rate base of the Calpeco Electric System as energy produced from the project is being consumed by the utility's customers.

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2017Fourth Quarter Results From Operations

Key Financial Information	Three Months Ended December 31
(all dollar amounts in $ millions except per share information)	2017		2016
Revenue	$	523.4	$	310.2
Net earnings attributable to shareholders	60.0		46.3
Cash provided by operating activities	169.8		121.9
Adjusted Net Earnings1	85.9		51.4
Adjusted EBITDA1	233.4		138.3
Adjusted Funds from Operations1	159.1		96.4
Dividends declared to common shareholders	64.0		39.2
Weighted average number of common shares outstanding	412,632,308		273,952,963
Per share
Basic net earnings	$	0.14	$	0.16
Diluted net earnings	$	0.14	$	0.16
Adjusted Net Earnings1,2	$	0.20	$	0.18
Dividends declared to common shareholders	$	0.15	$	0.14

1	See Non-GAAP Financial Measures
2	APUC uses per share Adjusted Net Earnings to enhance assessment and understanding of the performance of APUC.

For the three months ended December 31, 2017, APUC experienced an average U.S. exchange rate of approximately 1.2715 as compared to 1.3343 in the same period in 2016. As such, any quarter over quarter variance in revenue or expenses, in local currency, at any of APUC’s U.S. entities is affected by a change in the average exchange rate upon conversion to APUC’s reporting currency.

For the three months ended December 31, 2017, APUC reported total revenue of $523.4 million as compared to $310.2 million during the same period in 2016, an increase of $213.2 million. The major factors resulting in the increase in APUC revenue in the three months ended December 31, 2017 as compared to the corresponding period in 2016 are set out as follows:

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

(all dollar amounts in $ millions)	Three Months Ended December 31
Comparative Prior Period Revenue	$	310.2
LIBERTY POWER GROUP
Existing Facilities
Hydro: Decrease due to lower pricing in Hydro Quebec PPA renewals and a decline in pricing in the Western Region, partially offset by higher overall production.	(0.4		)
Wind Canada: Increase primarily due to higher production and annual rate increases in PPAs.	1.9
Wind U.S.: Increase primarily due to higher overall production.	1.3
Solar Canada: Increase primarily due to higher production.	0.1
Solar U.S.: Increase primarily due to higher production.	0.1
Thermal: Increase is primarily due to higher overall production as well as a new capacity-based contract at the Sanger Thermal Facility.	2.9
Other:	(0.5		)
	5.4
New Facilities
Wind US: Acquisition of Deerfield Wind Facility in March 2017.	9.5
Solar US: Bakersfield II Solar Facility was placed in service in December 2016.	0.3
	9.8
Foreign Exchange	(2.3		)
LIBERTY UTILITIES GROUP
Existing Facilities
Electricity: Decrease primarily due to retroactive recognition of 12 months of revenue in Q4 of 2016 arising from the 2016 rate case at the Calpeco Electric System.	(7.2		)
Gas: Increase primarily due to higher demand and pass through gas costs at the New England and Midstates Gas Systems from increased heating degree days, partially offset by lower pass through gas costs at the EnergyNorth Gas System.	14.5
Water: Decrease primarily due to divestiture of Mountain Water System from condemnation proceedings on June 22, 2017.	(2.9		)
Other: Decrease primarily due to lower contracted services.	(1.8		)
	2.6
New Facilities
Electricity: Acquisition of both Empire's electric distribution system ($180.8 million) on January 1, 2017 and the Luning Solar Facility ($3.6 million) on February 15, 2017.	184.4
Gas: Acquisition of Empire's gas distribution system on January 1, 2017.	14.6
Water: Acquisition of Empire's water distribution system on January 1, 2017.	0.6
Other: Acquisition of Empire's fiber optic operations on January 1, 2017.	2.0
	201.6
Rate Cases
Electricity: Implementation of new rates at the Granite State Electric System.	1.0
Gas: Implementation of new rates at the EnergyNorth, Midstates, New England, and Peach State Gas Systems.	4.1
Water: Implementation of new rates at the Park Water System.	2.0
	7.1
Foreign Exchange	(11.0		)
Current Period Revenue	$	523.4

A more detailed discussion of these factors is presented within the business unit analysis.

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

For the three months ended December 31, 2017, net earnings attributable to shareholders totaled $60.0 million as compared to $46.3 million during the same period in 2016, an increase of $13.7 million or 29.6%. The increase was due to a $101.6 millionincrease in earnings from operating facilities and a $1.1 milliondecrease in acquisition related costs. These items were partially offset by a $5.6 millionincrease in administration charges, $35.4 millionincrease in depreciation and amortization expenses, $0.3 milliondecrease in foreign exchange gain, $3.7 millionincrease in interest expense, $0.6 milliondecrease in interest, dividend, equity and other income, $3.3 milliondecrease in other gains, $2.3 milliondecrease in gains on long lived assets, $8.9 milliondecrease in gains from derivative instruments, $2.4 milliondecrease in net effect of non-controlling interests, and a $26.5 millionincrease in income tax expense (tax explanations are discussed in APUC: Corporate and Other Expenses) as compared to the same period in 2016.

During the three months ended December 31, 2017, cash provided by operating activities totaled $169.8 million as compared to cash provided by operating activities of $121.9 million during the same period in 2016. During the three months ended December 31, 2017, Adjusted Funds from Operations totaled $159.1 million compared to Adjusted Funds from Operations of $96.4 million during the same period in 2016. The change in Adjusted Funds from Operations in the three months ended December 31, 2017 is primarily due to increased earnings from operations (including Empire) as compared to the same period in 2016.

During the three months ended December 31, 2017, Adjusted EBITDA totaled $233.4 million as compared to $138.3 million during the same period in 2016, an increase of $95.1 million or 68.8%. A more detailed analysis of these factors is presented within the reconciliation of Adjusted EBITDA to net earnings set out below (see Non-GAAP Financial Measures).

2017Annual Results From Operations

Key Financial Information	Twelve Months Ended December 31
(all dollar amounts in $ millions except per share information)	2017		2016		2015
Revenue	$	1,977.8	$	1,096.0	$	1,027.9
Net earnings attributable to shareholders from continuing operations	193.1		130.9		118.5
Net earnings attributable to shareholders	193.1		130.9		117.5
Cash provided by operating activities	457.8		287.9		261.9
Adjusted Net Earnings1	292.1		161.6		121.5
Adjusted EBITDA1	883.4		476.9		375.4
Adjusted Funds from Operations1	614.5		356.4		287.4
Dividends declared to common shareholders	242.5		149.2		124.8
Weighted average number of common shares outstanding	382,323,434		271,832,430		253,172,088
Per share
Basic net earnings from continuing operations	$	0.48	$	0.44	$	0.43
Basic net earnings	$	0.48	$	0.44	$	0.42
Diluted net earnings	$	0.47	$	0.44	$	0.42
Adjusted Net Earnings1,2	$	0.74	$	0.57	$	0.46
Dividends declared to common shareholders	$	0.61	$	0.55	$	0.49
Total assets	10,533.6		8,249.5		4,991.7
Long term debt3	3,864.5		4,272.0		1,486.8

1	See Non-GAAP Financial Measures.
2	APUC uses per share Adjusted Net Earnings to enhance assessment and understanding of the performance of APUC.
3	Includes current and long-term portion of debt and convertible debentures per the financial statements.

For the twelve months ended December 31, 2017, APUC experienced an average U.S. exchange rate of approximately 1.2980 as compared to 1.3253 in the same period in 2016. As such, any year-over-year variance in revenue or expenses, in local currency, at any of APUC’s U.S. entities is affected by a change in the average exchange rate upon conversion to APUC’s reporting currency.

For the twelve months ended December 31, 2017, APUC reported total revenue of $1,977.8 million as compared to $1,096.0 million during the same period in 2016, an increase of $881.8 million or 80.5%. The major factors resulting in the increase in APUC revenue for the twelve months ended December 31, 2017 as compared to the corresponding period in 2016 are set out as follows:

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

(all dollar amounts in $ millions)	Twelve Months Ended December 31
Comparative Prior Period Revenue	$	1,096.0
LIBERTY POWER GROUP
Existing Facilities
Hydro: Decrease primarily due to prior year recognition of a Global Adjustment payment from the Ontario IESO, and lower pricing in Hydro Quebec PPA renewals, coupled with lower production in the Maritime and Western Regions.	(7.5		)
Wind Canada: Increase primarily due to higher production and annual PPA rate increases.	2.2
Wind U.S.: Decrease primarily due to lower REC pricing, partially offset by higher production at Minonk and Shady Oaks Wind Facilities.	(0.8		)
Solar Canada: Decrease primarily due to lower production, largely in the second quarter of 2017.	(0.6		)
Solar U.S.: Decrease primarily due to business interruption insurance payments received in the prior year.	(0.4		)
Thermal: Increase primarily due to higher pass through fuel costs at the Windsor Locks Thermal Facility, as well as a new capacity-based contract at the Sanger Thermal Facility.	4.2
Other: Decrease primarily due to the shutdown of the hydro mulch business at the Sanger Thermal Facility.	(1.9		)
	(4.8		)
New Facilities
Wind U.S.: Acquisition of Odell (September 2016) and Deerfield (March 2017) Wind Facilities.	40.8
Solar U.S.: Bakersfield II Solar Facility was placed in service in December 2016.	2.1
	42.9
Foreign Exchange	(3.6		)
LIBERTY UTILITIES GROUP
Existing Facilities
Electricity: Decrease primarily due to lower pass through energy costs at the Calpeco Electric System.	(8.3		)
Gas: Increase primarily due to higher consumption at the EnergyNorth and New England Gas Systems due to higher heating degree days combined with higher pass through gas costs at the Peach State Gas System.	38.0
Water: Decrease primarily due divestiture of Mountain Water System from condemnation proceedings on June 22, 2017.	(6.5		)
Other: Decrease primarily due to lower contracted services.	(6.0		)
	17.2
New Facilities
Electricity: Acquisition of both Empire's electric distribution system ($754.6 million) on January 1, 2017 and the Luning Solar Facility ($14.7 million) on February 15, 2017.	769.3
Gas: Acquisition of Empire's gas distribution system on January 1, 2017.	46.9
Water: Acquisition of Empire's water distribution system on January 1, 2017.	2.7
Other: Acquisition of Empire's fiber optic operations on January 1, 2017.	8.1
	827.0
Rate Cases
Electricity: Implementation of new rates at the Granite State Electric System.	5.2
Gas: Implementation of new rates at the EnergyNorth, Midstates, New England, and Peach State Gas Systems.	12.5
Water: Implementation of new rates at the Park Water, Bella Vista, Rio Rico and Black Mountain Water and Wastewater Systems.	6.1
	23.8
Foreign Exchange	(20.7		)
Current Period Revenue	$	1,977.8

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

A more detailed discussion of these factors is presented within the business unit analysis.

For the twelve months ended December 31, 2017, net earnings attributable to shareholders totaled $193.1 million as compared to $130.9 million during the same period in 2016, an increase of $62.2 million. The increase was due to a $401.4 millionincrease in earnings from operating facilities, $1.4 millionincrease in interest, dividend, equity and other income, and $23.6 millionincrease in net effect of non-controlling interests. These items were partially offset by an $18.2 million increase in administration charges, $139.5 million increase in depreciation and amortization expenses, $0.8 milliondecrease in foreign exchange gains, $71.0 million increase in interest expense, $11.8 milliondecrease in other gains, $50.8 million increase in acquisition costs, $0.8 milliondecrease in gain on long lived assets, $13.2 milliondecrease on gains from derivative instruments and $58.1 millionincrease in income tax expense (tax explanations are discussed in APUC: Corporate and Other Expenses) as compared to the same period in 2016.

During the twelve months ended December 31, 2017, cash provided by operating activities totaled $457.8 million as compared to cash provided by operating activities of $287.9 million during the same period in 2016. During the twelve months ended December 31, 2017, Adjusted Funds from Operations, a non-GAAP measure, totaled $614.5 million as compared to Adjusted Funds from Operations of $356.4 million the same period in 2016, an increase of $258.1 million.

Adjusted EBITDA in the twelve months ended December 31, 2017 totaled $883.4 million as compared to $476.9 million during the same period in 2016, an increase of $406.5 million or 85.2%. A detailed analysis of this variance is presented within the reconciliation of Adjusted EBITDA to net earnings set out below (see Non-GAAP Financial Measures).

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

2017 Adjusted EBITDA Summary

Adjusted EBITDA (see Non-GAAP Financial Measures) for the three months ended December 31, 2017 totaled $233.4 million as compared to $138.3 million during the same period in 2016, an increase of $95.1 million or 68.8%. Adjusted EBITDA for the twelve months ended December 31, 2017 totaled $883.4 million as compared to $476.9 million during the same period in 2016, an increase of $406.5 million or 85.2%. The breakdown of Adjusted EBITDA by the Company's main operating segments and a summary of changes are shown below.

Adjusted EBITDA by business units	Three Months Ended December 31						Twelve Months Ended December 31
(all dollar amounts in $ millions)	2017			2016			2017			2016
Liberty Power Operating Profit	$	70.8		$	61.9		$	250.9		$	217.3
Liberty Utilities Group Operating Profit	180.7			85.9			694.1			300.5
Administrative Expenses	(18.7		)	(13.1		)	(64.5		)	(46.3		)
Other Income & Expenses	0.6			3.6			2.9			5.4
Total Algonquin Power & Utilities Adjusted EBITDA	$	233.4		$	138.3		$	883.4		$	476.9
Change in Adjusted EBITDA ($)	$	95.1					$	406.5
Change in Adjusted EBITDA (%)	68.8		%				85.2		%

Change in Adjusted EBITDA	Three Months Ended December 31, 2017
(all dollar amounts in $ millions)	Power			Utilities			Corporate			Total
Prior period balances	$	61.9		$	85.9		$	(9.5	)	$	138.3
Existing Facilities	7.8			(5.6		)	(3.0		)	(0.8		)
New Facilities	3.0			97.3			—			100.3
Rate Cases	—			7.1			—			7.1
Foreign Exchange Impact	(1.9		)	(4.0		)	—			(5.9		)
Administrative Expenses	—			—			(5.6		)	(5.6		)
Total change during the period	$	8.9		$	94.8		$	(8.6	)	$	95.1
Current period balances	$	70.8		$	180.7		$	(18.1	)	$	233.4

Change in Adjusted EBITDA	Twelve Months Ended December 31, 2017
(all dollar amounts in $ millions)	Power			Utilities			Corporate			Total
Prior period balances	$	217.3		$	300.5		$	(40.9	)	$	476.9
Existing Facilities	0.9			(4.5		)	(2.6		)	(6.2		)
New Facilities	34.9			381.0			—			415.9
Rate Cases	—			23.8			—			23.8
Foreign Exchange Impact	(2.2		)	(6.7		)	—			(8.9		)
Administration Expenses	—			—			(18.1		)	(18.1		)
Total change during the period	$	33.6		$	393.6		$	(20.7	)	$	406.5
Current period balances	$	250.9		$	694.1		$	(61.6	)	$	883.4

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

LIBERTY POWER GROUP

2017 Electricity Generation Performance
	Long Term Average Resource	Three Months Ended December 31		Long Term Average Resource	Twelve Months Ended December 31
(Performance in GW-hrs sold)		2017	2016		2017	2016
Hydro Facilities:
Maritime Region	37.6	34.9	21.9	148.2	129.7	144.1
Quebec Region	72.6	67.5	64.0	273.3	270.6	267.5
Ontario Region	31.9	30.6	28.6	136.0	129.5	126.8
Western Region	12.6	10.5	18.1	65.0	59.6	66.1
	154.7	143.5	132.6	622.5	589.4	604.5
Wind Facilities:
St. Damase	22.7	24.0	20.4	76.9	74.3	74.4
St. Leon	121.4	138.7	130.8	430.2	444.2	417.3
Red Lily1	24.1	29.2	25.4	88.5	91.6	82.6
Morse	30.5	33.1	27.7	108.8	106.4	94.8
Sandy Ridge	43.6	42.0	51.8	158.3	153.3	155.8
Minonk	189.8	203.5	184.9	673.7	673.7	635.8
Senate	140.0	126.6	136.7	520.4	492.8	504.4
Shady Oaks	100.5	108.7	104.4	355.6	365.5	323.9
Odell2	238.0	244.6	211.2	831.8	807.2	297.7
Deerfield3	160.0	164.3	—	472.6	449.3	—
	1,070.6	1,114.7	893.3	3,716.8	3,658.3	2,586.7
Solar Facilities:
Cornwall	2.2	2.1	1.9	14.7	14.4	15.6
Bakersfield I	8.9	8.7	7.4	52.8	48.3	45.9
Bakersfield II4	4.1	4.0	—	24.4	22.2	—
	15.2	14.8	9.3	91.9	84.9	61.5
Renewable Energy Performance	1,240.5	1,273.0	1,035.2	4,431.2	4,332.6	3,252.7
Thermal Facilities:
Windsor Locks	N/A5	31.8	30.9	N/A5	122.0	131.0
Sanger	N/A5	33.5	28.8	N/A5	86.0	118.7
		65.3	59.7		208.0	249.7
Total Performance		1,338.3	1,094.9		4,540.6	3,502.4

1	APUC owns a 75% equity interest in the Red Lily Wind Facility but accounts for the facility using the equity method. The production figures represent full energy produced by the facility.
2	The Odell Wind Facility achieved COD on July 29, 2016 and was treated as an equity investment until September 15, 2016 at which time the Company acquired the remaining 50% ownership in the facility.
3	The Deerfield Wind Facility achieved COD on February 21, 2017 and was treated as an equity investment until March 14, 2017 at which time the Company acquired the remaining 50% ownership in the facility. The long-term average resources ("LTAR") and production noted above represents all production from the date of COD.
4	The Bakersfield II Solar Facility achieved COD on January 11, 2017 in accordance with the terms of the PPA. The LTAR and production noted above represents all production from the date of COD.
5	Natural gas fired co-generation facility.

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

2017Fourth Quarter Liberty Power Group Performance

For the three months ended December 31, 2017, the Liberty Power Group generated 1,338.3 GW-hrs of electricity as compared to 1,094.9 GW-hrs during the same period of 2016.

For the three months ended December 31, 2017, the hydro facilities generated 143.5 GW-hrs of electricity as compared to 132.6 GW-hrs produced in the same period in 2016, an increase of 8.2%. Electricity generated represented 92.8% of long-term average resources ("LTAR") as compared to 85.7% during the same period in 2016. During the quarter, all regions were below their respective LTAR.

For the three months ended December 31, 2017, the wind facilities produced 1,114.7 GW-hrs of electricity as compared to 893.3 GW-hrs produced in the same period in 2016, an increase of 24.8%. The higher generation was primarily due to the addition of the Deerfield Wind Facility which achieved COD on February 21, 2017. This increase was partially offset by lower production at the Senate and Sandy Ridge Wind Facilities. During the three months ended December 31, 2017, the wind facilities (excluding the Deerfield Wind Facility) generated electricity equal to 104.3% of LTAR as compared to 98.0% during the same period in 2016.

For the three months ended December 31, 2017, the solar facilities generated 14.8 GW-hrs of electricity as compared to 9.3 GW-hrs of electricity in the same period in 2016, an increase of 59.1%. The increase in production is primarily due to the addition of the Bakersfield II Solar Facility which achieved COD on January 11, 2017. The solar facilities (excluding Bakersfield II) production was 2.7%below its LTAR as compared to 16.2%below in the same period in 2016.

For the three months ended December 31, 2017, the thermal facilities generated 65.3 GW-hrs of electricity as compared to 59.7 GW-hrs of electricity during the same period in 2016. During the same period, the Windsor Locks Thermal Facility generated 136.9 billion lbs of steam as compared to 129.3 billion lbs of steam during the same period in 2016.

2017AnnualLiberty Power Group Performance

For the twelve months ended December 31, 2017, the Liberty Power Group generated 4,540.6 GW-hrs of electricity as compared to 3,502.4 GW-hrs during the same period of 2016.

For the twelve months ended December 31, 2017, the hydro facilities generated 589.4 GW-hrs of electricity as compared to 604.5 GW-hrs produced in the same period in 2016, a decrease of 2.5%. Electricity generated represented 94.7% of long-term projected average resources as compared to 97.1% during the same period in 2016. The decrease is primarily due to reduced hydrology in the Maritime and Western Region's partially offset by increased generation in the Quebec and Ontario Regions.

For the twelve months ended December 31, 2017, the wind facilities produced 3,658.3 GW-hrs of electricity as compared to 2,586.7 GW-hrs produced in the same period in 2016, an increase of 41.4%. During the twelve months ended December 31, 2017, the wind facilities generated electricity equal to 98.4% of LTAR as compared to 93.9% during the same period in 2016. The increase in production was primarily due to higher production at the Shady Oaks, Minonk and St. Leon Wind Facilities as well as the incremental electricity generated at the Deerfield and Odell Wind Facilities which achieved COD on February 21, 2017 and July 29, 2016, respectively.

For the twelve months ended December 31, 2017, the solar facilities generated 84.9 GW-hrs of electricity as compared to 61.5 GW-hrs of electricity produced in the same period in 2016, an increase of 38.0%. The increase in production is primarily due to the addition of the Bakersfield II Solar Facility which achieved COD on January 11, 2017. The solar facilities (excluding Bakersfield II) production was 7.1%below its LTAR as compared to 8.9%below in the same period in 2016.

For the twelve months ended December 31, 2017, the thermal facilities generated 208.0 GW-hrs of electricity as compared to 249.7 GW-hrs of electricity during the same period in 2016. During the same period, the Windsor Locks Thermal Facility generated 559.1 billion lbs of steam as compared to 552.5 billion lbs of steam during the same period in 2016.

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

2017 Liberty Power Group Operating Results
	Three Months Ended December 31						Twelve Months Ended December 31
(all dollar amounts in $ millions)	2017			2016			2017			2016
Revenue1
Hydro	$	14.0		$	14.6		$	58.2		$	66.5
Wind	54.0			42.6			171.6			128.2
Solar	2.0			1.6			14.0			12.9
Thermal	11.1			8.2			38.8			35.5
Total Revenue	$	81.1		$	67.0		$	282.6		$	243.1
Less:
Cost of Sales - Energy2	(1.9		)	(1.8		)	(6.5		)	(5.8		)
Cost of Sales - Thermal	(5.8		)	(4.4		)	(18.9		)	(15.5		)
Realized gain/(loss) on hedges3	—			—			(0.7		)	(1.0		)
Net Energy Sales	$	73.4		$	60.8		$	256.5		$	220.8
Renewable Energy Credits ("REC")4	5.5			6.3			17.1			20.2
Other Revenue	0.1			0.5			0.5			2.4
Total Net Revenue	$	79.0		$	67.6		$	274.1		$	243.4
Expenses & Other Income
Operating expenses	(21.9		)	(20.2		)	(86.7		)	(72.3		)
Interest, dividend, equity and other income	1.1			0.9			3.7			5.2
HLBV income5	12.6			13.6			59.8			41.0
Divisional Operating Profit6,7	$	70.8		$	61.9		$	250.9		$	217.3

1	While most of the Liberty Power Group's PPAs include annual rate increases, a change to the weighted average production levels resulting from higher average production from facilities that earn lower energy rates can result in a lower weighted average energy rate earned by the division as compared to the same period in the prior year.
2	Cost of Sales - Energy consists of energy purchases in the Maritime Region to manage the energy sales from the Tinker Hydro Facility which is sold to retail and industrial customers under multi-year contracts.
3	See financial statements note 25(b)(iv).
4	Qualifying renewable energy projects receive RECs for the generation and delivery of renewable energy to the power grid. The energy credit certificates represent proof that 1 MW of electricity was generated from an eligible energy source.
5	HLBV income represents the value of net tax attributes earned by the Liberty Power Group in the period primarily from electricity generated by certain of its U.S. wind power and U.S. solar generation facilities.
6	Certain prior year items have been reclassified to conform to current year presentation.
7	See Non-GAAP Financial Measures.

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

2017Fourth Quarter Operating Results

For the three months ended December 31, 2017, the Liberty Power Group's facilities generated $70.8 million of operating profit as compared to $61.9 million during the same period in 2016, which represents an increase of $8.9 million or 14.4%, excluding corporate administration expenses.

Highlights of the changes are summarized in the following table:

(all dollar amounts in $ millions)	Three Months Ended December 31
Prior Period Operating Profit	$	61.9
Existing Facilities
Hydro: Decrease due to lower pricing in Hydro Quebec PPA renewals and a decline in pricing in the Western Region, partially offset by higher overall production.	(0.6		)
Wind Canada: Increase primarily due to higher production and annual PPA rate increases.	1.9
Wind U.S.: Increase primarily due to higher production and HLBV income at the Minonk and Odell Wind Facilities.	4.7
Solar Canada: Increase primarily due to higher production.	0.1
Solar U.S.: Increase primarily due to higher production.	0.3
Thermal: Increase primarily due to higher overall production as well as a new capacity-based contract at the Sanger Thermal Facility.	1.3
Other:	0.1
	7.8
New Facilities
Wind U.S.: Acquisition of Deerfield Wind Facility in March 2017.	2.2
Solar U.S.: Bakersfield II was placed in service in December 2016.	0.8
	3.0
Foreign Exchange	(1.9		)
Current Period Divisional Operating Profit	$	70.8

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

2017 Annual Operating Results

For the twelve months ended December 31, 2017, the Liberty Power Group's facilities generated $250.9 million of operating profit as compared to $217.3 million during the same period in 2016, which represents an increase of $33.6 million or 15.5%, excluding corporate administration expenses.

Highlights of the changes are summarized in the following table:

(all dollar amounts in $ millions)	Twelve Months Ended December 31
Prior Period Operating Profit	$	217.3
Existing Facilities
Hydro: Decrease primarily due to prior year recognition of a Global Adjustment payment from the Ontario IESO, and pricing settlement in the Quebec Region, coupled with lower production in the Maritime and Western Regions.	(8.2		)
Wind Canada: Increase primarily due to higher production and annual rate increases.	1.8
Wind U.S.: Increase primarily due to higher HLBV income and higher production at the Minonk and Shady Oaks Wind Facilities.	6.7
Solar Canada: Decrease primarily due to lower production, largely in the second quarter of 2017.	(0.2		)
Solar U.S.: Decrease primarily due to business interruption insurance payments received in the prior year.	(0.4		)
Thermal: Increase primarily due to higher pass through fuel costs at to the Windsor Locks Thermal Facility, as well as a new capacity-based contract at the Sanger Thermal Facility.	0.4
Other:	0.8
	0.9
New Facilities
Wind U.S.: Acquisition of Odell (September 2016) and Deerfield (March 2017) Wind Facilities.	31.3
Solar U.S.: Bakersfield II was placed in service in December 2016.	3.6
	34.9
Foreign Exchange	(2.2		)
Current Period Divisional Operating Profit	$	250.9

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

LIBERTY UTILITIES GROUP

The Liberty Utilities Group operates rate-regulated utilities that provide distribution services to approximately 762,000 connections in the natural gas, electric, water and wastewater sectors. On January 1, 2017, the Liberty Utilities Group completed the acquisition of Empire. Empire is a vertically-integrated utility providing electric, natural gas and water service serving approximately 221,000 customers in Missouri, Kansas, Oklahoma, and Arkansas. The Liberty Utilities Group's strategy is to grow its business organically and through business development activities while using prudent acquisition criteria.  The Liberty Utilities Group believes that its business results are maximized by building constructive regulatory and customer relationships, and enhancing connections in the communities in which it operates.

Utility System Type	As at December 31
	2017			2016
(all dollar amounts in U.S. $ millions)	Assets		Total Connections1	Assets		Total Connections1
Electricity	$	2,479.9	265,000	$	378.4	94,000
Natural Gas	996.1		337,000	845.9		293,000
Water and Wastewater	462.6		160,000	516.4		178,000
Total	$	3,938.6	762,000	$	1,740.7	565,000
Accumulated Deferred Income Taxes Liability	$	392.8		$	194.7

1 Total Connections represents the sum of all active and vacant connections.

The Liberty Utilities Group aggregates the performance of its utility operations by utility system type – electricity, natural gas, and water and wastewater systems.

The electric distribution systems are comprised of regulated electrical distribution utility systems and serve approximately 265,000 connections in the states of California, New Hampshire, Missouri, Kansas, Oklahoma, and Arkansas.

The natural gas distribution systems are comprised of regulated natural gas distribution utility systems and serve approximately 337,000 connections located in the states of New Hampshire, Illinois, Iowa, Missouri, Georgia, and Massachusetts.

The water and wastewater distribution systems are comprised of regulated water distribution and wastewater collection utility systems and serve approximately 160,000 connections located in the states of Arkansas, Arizona, California, Illinois, Missouri and Texas.

2017Fourth Quarter Usage Results

Electric Distribution Systems	Three Months Ended December 31
	2017	2016
Average Active Electric Connections For The Period
Residential	224,400	80,600
Commercial and industrial	39,200	12,500
Total Average Active Electric Connections For The Period	263,600	93,100
Customer Usage (GW-hrs)
Residential	571.7	142.5
Commercial and industrial	882.3	225.0
Total Customer Usage (GW-hrs)	1,454.0	367.5

For the three months ended December 31, 2017, the electric distribution systems' usage totaled 1,454.0 GW-hrs as compared to 367.5 GW-hrs for the same period in 2016, an increase of 1,086.5 GW-hrs or 295.6%. The addition of Empire accounted for 1,091.6 GW-hrs of the increase. Excluding Empire, usage was 5.1 GW-hrs, or 1.4%, lower due to lower commercial usage at the Calpeco Electric System.

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

Natural Gas Distribution Systems	Three Months Ended December 31
	2017	2016
Average Active Natural Gas Connections For The Period
Residential	286,700	248,100
Commercial and industrial	31,700	26,600
Total Average Active Natural Gas Connections For The Period	318,400	274,700
Customer Usage (MMBTU)
Residential	5,196,000	3,737,000
Commercial and industrial	4,282,000	3,446,000
Total Customer Usage (MMBTU)	9,478,000	7,183,000

For the three months ended December 31, 2017, usage at the natural gas distribution systems totaled 9,478,000 MMBTU as compared to 7,183,000 MMBTU during the same period in 2016,an increase of 2,295,000MMBTU, or 32.0%. The addition of Empire accounted for 1,069,000 MMBTU of the increase. Excluding Empire, usage was 1,226,000 MMBTU, or 17.1%, higher primarily due to increased consumption at the Midstates and Peach State Gas Systems.

Water and Wastewater Distribution Systems	Three Months Ended December 31
	2017	2016
Average Active Connections For The Period
Wastewater connections	41,400	41,100
Water distribution connections	111,800	129,400
Total Average Active Connections For The Period	153,200	170,500
Gallons Provided
Wastewater treated (millions of gallons)	555	542
Water provided (millions of gallons)	3,909	4,113
Total Gallons Provided	4,464	4,655

During the three months ended December 31, 2017, the water and wastewater distribution systems provided approximately 3,909 million gallons of water to its customers and treated approximately 555 million gallons of wastewater as compared to 4,113 million gallons of water provided and 542 million gallons of wastewater treated during the same period in 2016. The decrease in the gallons of water provided to customers can be attributed to the disposition of the Mountain Water System in Montana. Excluding the Mountain Water System, the water provided to customers was approximately 289 million gallons, or 7%, higher.

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

2017Fourth Quarter Operating Results

	Three Months Ended December 31
	2017 U.S. $ (millions)			2016 U.S. $ (millions)			2017 Can $ (millions)			2016 Can $ (millions)
Revenue
Utility electricity sales and distribution	$	187.0		$	46.9		$	237.8		$	62.5
Less: cost of sales – electricity	(51.6		)	(20.6		)	(65.6		)	(27.5		)
Net Utility Sales - electricity	135.4			26.3			172.2			35.0
Utility natural gas sales and distribution	109.8			85.1			140.0			114.0
Less: cost of sales – natural gas	(53.1		)	(39.8		)	(67.7		)	(53.2		)
Net Utility Sales - natural gas	56.7			45.3			72.3			60.8
Utility water distribution & wastewater treatment sales and distribution	31.5			31.7			40.1			42.3
Less: cost of sales – water	(2.4		)	(2.2		)	(3.1		)	(3.0		)
Net Utility Sales - water distribution & wastewater treatment	29.1			29.5			37.0			39.3
Gas transportation	9.6			8.4			12.3			10.7
Other revenue	5.1			5.0			6.5			6.8
Net Utility Sales	235.9			114.5			300.3			152.6
Operating expenses	(96.6		)	(50.5		)	(123.1		)	(68.0		)
Other income	1.4			0.9			1.8			1.3
HLBV	1.3			—			1.7			—
Divisional Operating Profit1	$	142.0		$	64.9		$	180.7		$	85.9

1 Certain prior year items have been reclassified to conform with current year presentation.

For the three months ended December 31, 2017, the Liberty Utilities Group reported an operating profit (excluding corporate administration expenses) of U.S. $142.0 million as compared to U.S. $64.9 million for the comparable period in the prior year. Measured in Canadian dollars, the Group's operating profit was $180.7 million as compared to $85.9 million during the same period in 2016, which represents an increase of $94.8 million or 110%, excluding corporate administration expenses.

Highlights of the changes are summarized in the following table:

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

(all dollar amounts in $ millions)	Three Months Ended December 31
Prior Period Operating Profit	$	85.9
Existing Facilities
Electricity: Decrease primarily due to retroactive recognition of 12 months of revenue in Q4 of 2016 arising from the 2016 rate case at the Calpeco Electric System.	(6.4		)
Gas: Increase primarily due to higher consumption at the Midstates and EnergyNorth Gas Systems.	3.1
Water: Decrease primarily due to lower revenue as a result of the disposition of the Mountain Water System in Montana.	(2.2		)
Other: Decrease primarily due to lower contracted services.	(0.1		)
	(5.6		)
New Facilities
Electricity: Acquisition of both Empire's electric distribution system ($85.9 million) on January 1, 2017 and the Luning Solar Facility ($4.9 million) on February 15, 2017.	90.8
Gas: Acquisition of Empire's gas distribution system on January 1, 2017.	4.3
Water: Acquisition of Empire's water distribution system on January 1, 2017.	0.3
Other: Acquisition of Empire's fiber optic operations on January 1, 2017.	1.9
	97.3
Rate Cases
Electricity: Implementation of new rates at the Granite State Electric System.	1.0
Gas: Implementation of new rates at the EnergyNorth, Midstates, New England, and Peach State Gas Systems.	4.1
Water: Implementation of new rates at the Park Water System.	2.0
	7.1
Foreign Exchange	(4.0		)
Current Period Divisional Operating Profit	$	180.7

2017Annual Usage Results

Electric Distribution Systems	Twelve Months Ended December 31
	2017	2016
Average Active Electric Connections For The Period
Residential	223,700	80,400
Commercial and industrial	39,200	12,500
Total Average Active Electric Connections For The Period	262,900	92,900
Customer Usage (GW-hrs)
Residential	2,320.1	567.0
Commercial and industrial	3,523.1	895.2
Total Customer Usage (GW-hrs)	5,843.2	1,462.2

For the twelve months ended December 31, 2017, the electric distribution systems' usage totaled 5,843.2 GW-hrs as compared to 1,462.2 GW-hrs for the same period in 2016, an increase of 4,381.0 GW-hrs. The addition of Empire accounted for 4,386.3 GW-hrs of the increase. Excluding Empire, usage was 5.3 GW-hrs, or 0.4%, lower due to decreased usage by commercial customers at the Granite State Electric System.

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

Natural Gas Distribution Systems	Twelve Months Ended December 31
	2017	2016
Average Active Natural Gas Connections For The Period
Residential	287,100	249,000
Commercial and industrial	31,700	26,600
Total Average Active Natural Gas Connections For The Period	318,800	275,600
Customer Usage (MMBTU)
Residential	17,621,000	15,346,000
Commercial and industrial	12,672,000	11,361,000
Total Customer Usage (MMBTU)	30,293,000	26,707,000

For the twelve months ended December 31, 2017, usage at the natural gas distribution systems totaled 30,293,000 MMBTU as compared to 26,707,000 MMBTU during the same period in 2016,an increase of 3,586,000 MMBTU or 13.4%. The addition of Empire accounted for 2,997,000 MMBTU of the increase. Excluding Empire, usage was 589,000 MMBTU, or 2.2%, higher due to increased usage at the EnergyNorth and New England Gas Systems.

Water and Wastewater Distribution Systems	Twelve Months Ended December 31
	2017	2016
Average Active Connections For The Period
Wastewater connections	41,000	41,100
Water distribution connections	121,400	131,400
Total Average Active Connections For The Period	162,400	172,500
Gallons Provided
Wastewater treated (millions of gallons)	2,226	2,231
Water provided (millions of gallons)	16,905	17,936
Total Gallons Provided	19,131	20,167

During the twelve months ended December 31, 2017, the water and wastewater distribution systems provided approximately 16,905 million gallons of water to its customers and treated approximately 2,226 million gallons of wastewater as compared to 17,936 million gallons of water and 2,231 million gallons of wastewater during the same period in 2016. The decrease in the gallons of water provided to customers can be attributed to the disposition of the Mountain Water System in Montana. Excluding the Mountain Water System, the water provided to customers was approximately 2,295 million gallons, or 14%, higher.

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

2017Annual Operating Results

	Twelve Months Ended December 31
	2017 U.S. $ (millions)			2016 U.S. $ (millions)			2017 Can $ (millions)			2016 Can $ (millions)
Revenue
Utility electricity sales and distribution	$	763.5		$	171.7		$	989.2		$	228.1
Less: cost of sales – electricity	(222.4		)	(90.0		)	(288.2		)	(119.8		)
Net Utility Sales - electricity	541.1			81.7			701.0			108.3
Utility natural gas sales and distribution	346.0			276.8			450.7			371.4
Less: cost of sales – natural gas	(141.7		)	(105.0		)	(184.5		)	(142.1		)
Net Utility Sales - natural gas	204.3			171.8			266.2			229.3
Utility water distribution & wastewater treatment sales and distribution	140.1			137.4			181.9			181.7
Less: cost of sales – water	(9.5		)	(9.2		)	(12.3		)	(12.2		)
Net Utility Sales - water distribution & wastewater treatment	130.6			128.2			169.6			169.5
Gas transportation	31.2			25.7			40.7			34.3
Other revenue	11.8			11.0			15.2			14.6
Net Utility Sales	919.0			418.4			1,192.7			556.0
Operating expenses	(393.7		)	(196.1		)	(512.0		)	(260.6		)
Other income	4.2			3.9			5.4			5.1
HLBV	6.2			—			8.0			—
Divisional Operating Profit1	$	535.7		$	226.2		$	694.1		$	300.5

1 Certain prior year items have been reclassified to conform with current year presentation.

For the twelve months ended December 31, 2017, the Liberty Utilities Group reported an operating profit (excluding corporate administration expenses) of U.S. $535.7 million as compared to U.S. $226.2 million for the comparable period in the prior year. Measured in Canadian dollars, the Group's operating profit was $694.1 million as compared to $300.5 million during the same period in 2016, which represents an increase of $393.6 million or 131%, excluding corporate administration expenses.

Highlights of the changes are summarized in the following table:

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

(all dollar amounts in $ millions)	Twelve Months Ended December 31
Prior Period Operating Profit	$	300.5
Existing Facilities
Gas: Increase primarily due to higher consumption at the EnergyNorth Gas System.	4.5
Water: Decrease primarily due to lower revenue as a result of the disposition of the Mountain Water System in Montana.	(5.3		)
Other: Decrease primarily due to lower contracted services.	(3.7		)
	(4.5		)
New Facilities
Electricity: Acquisition of both Empire's electric distribution system ($341.4 million) on January 1, 2017 and the Luning Solar Facility ($20.7 million) on February 15, 2017.	362.1
Gas: Acquisition of Empire's gas distribution system on January 1, 2017.	11.9
Water: Acquisition of Empire's water distribution system on January 1, 2017.	1.3
Other: Acquisition of Empire's fiber optic operations on January 1, 2017.	5.7
	381.0
Rate Cases
Electricity: Implementation of new rates at the Granite State Electric System.	5.2
Gas: Implementation of new rates at the EnergyNorth, Midstates, New England, and Peach State Gas Systems.	12.5
Water: Implementation of new rates at the Park Water, Bella Vista, Rio Rico and Black Mountain Water and Wastewater Systems.	6.1
	23.8
Foreign Exchange	(6.7		)
Current Period Divisional Operating Profit	$	694.1

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

Regulatory Proceedings

The following table summarizes the major regulatory proceedings currently underway within the Liberty Utilities Group:

Utility	State	Regulatory Proceeding Type	Rate Request U.S. $ (millions)	Current Status
Completed Rate Cases
Granite State Electric System	New Hampshire	General Rate Case ("GRC")	$7.7	Final Order issued in April 2017 approving a U.S. $6.2 million rate increase effective May 1, 2017, and two additional rate increases of approximately U.S. $0.2 million and U.S. $0.3 million effective May 1, 2018 and May 1, 2019, respectively.
New England Gas	Massachusetts	Gas System Enhancement Plan ("GSEP")	$3.8	Final Order issued in April 2017 approving a U.S. $2.9 million rate increase effective May 1, 2017.
Illinois Gas System	Illinois	GRC	$3.0	Final Order issued in May 2017 approving a U.S. $2.2 million rate increase effective June 7, 2017.
Oklahoma Electricity System	Oklahoma	GRC	$3.0	In August 2017, in lieu of authorizing the proposed rate increase the Oklahoma Corporation Commission ordered an immediate increase of U.S. $1.0 million to capture the return on and of major capital investments related to plant upgrades and authorized Liberty Utilities to return in 2018 to seek the remaining proposed increases.
Calpeco Electric	California	Turquoise Solar Project	$3.0	Final Order issued in December 2017 approving the Settlement Agreement between Liberty Calpeco and the Office of Ratepayer Advocates dated June 30, 2017 which authorizes Liberty Calpeco to acquire, own, and operate the 10 MW, U.S. $15.7 million Turquoise Solar Project.
Calpeco Electric	California	Post-Test Year Adjustment Mechanism	$2.2	Final Order issued in November 2017 approving a U.S $2.2 million rate increase effective January 1, 2018, based on the additional costs related to the Luning Solar Project.
Various	Various	Various	$4.8	Other rate cases closed in 2017 & 2018 with a combined approved rate increase of U.S. $2.8 million include: Entrada Del Oro Water (U.S. $0.2 million), Georgia Gas GRAM (U.S. $0.6 million), New England Gas Decoupling (U.S. $0.2 million), Iowa Gas GRC (U.S. $0.9 million), and Kansas Asbury Environmental and Riverton Cost Recovery Rider (U.S. $0.9 million).

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

Utility	State	Regulatory Proceeding Type	Rate Request U.S. $ (millions)	Current Status
Pending Rate Cases
EnergyNorth Gas System	New Hampshire	GRC	$19.7	On April 28, 2017, filed an application seeking an increase of U.S. $13.7 million (updated to U.S. $14.5 million), plus a step increase of U.S. $6.1 million (updated to U.S. $5.2 million) to be implemented in May 2018. Temporary rates of U.S. $7.8 million were requested to be effective as of July 1, 2017, and on June 30, 2017, the New Hampshire Public Utilities Commission (“NH Commission”) approved temporary rates of U.S. $6.8 million (87% of the requested amount) effective July 1, 2017 to be in place until the end of the Company's permanent rate case.
Litchfield Park Water & Sewer	Arizona	GRC	$5.1	On February 28, 2017, filed a water/sewer rate application (test year December 31, 2016) seeking a rate increase of U.S. $5.1 million. New rates are expected to be effective in Q4 2018.
Missouri Gas System	Missouri	GRC	$7.5	On September 29, 2017, filed an application seeking a rate increase of U.S. $7.5 million for test year ending June 30, 2017 with proforma adjustments through to March 31, 2018. New rates are expected to be effective in Q3 2018.
Apple Valley Ranchos Water & Park Water Systems	California	GRC	$2.1	On January 2, 2018, filed an application requesting an average rate increase of U.S. $0.7 million and U.S. $1.4 million, respectively and is to set rates for the three year period of 2019 to 2021.
New England Natural Gas System	Massachusetts	GSEP	$6.2	On October 31, 2017, filed the 2018 GSEP application requesting recovery of U.S. $6.2 million (effective May 1, 2018) for replacement of approximately 14 miles of eligible infrastructure.
Various	Various	Various	$4.3	Other pending rate case requests include: Woodmark/Tall Timbers Wastewater Systems (U.S. $1.6 million), Park Water System (U.S. $1.5 million), and Missouri Water System (U.S. $1.2 million).

Completed Rate Cases

On December 14, 2016, the Calpeco Electric System filed an application for approval of the 10 MW Turquoise Solar Project at an estimated cost of U.S. $15.7 million. On June 30, 2017, the Calpeco Electric System and the Office of Ratepayer Advocates filed a joint motion with the Commission requesting approval of its settlement agreement. On December 19, 2017, the Commission issued a decision approving the settlement agreement as filed. The Turquoise Solar Project costs will be included in the Calpeco Electric System's 2019 general rate case and is expected to have a rate impact of approximately U.S. $3.0 million (or 3% increase), which will be offset by future Energy Cost Adjustment Clause ("ECAC)" account reductions. The Turquoise Solar Project is expected to be in service by the fourth quarter of 2018.

On April 29, 2016, the Granite State Electric System filed a rate application seeking a U.S. $5.3 million annual revenue increase proposed for effect July 1, 2016, plus an additional U.S. $2.4 million annual step increase to recover the revenue requirement associated with capital additions made in 2016. The total permanent and step increase proposed was U.S. $7.7 million annually, or a 21.8% increase to distribution revenue. In June 2016, approval of a temporary rate increase of U.S. $2.4 million was issued, effective July 1, 2016. The final permanent rate increase was retroactive to the temporary rate effective date. In April 2017, an order was issued by the New Hampshire Public Utilities Commission ("NHPUC") approving a U.S. $3.8 million rate increase to annual distribution revenues along with an annual increase of U.S. $2.5 million for the revenue requirement associated with 2016 capital investment, both effective May 1, 2017 (achieving 82% of the requested increase). The difference between the U.S. $3.8 million permanent increase and the U.S. $2.4 million temporary rate level that was in effect since July 1, 2016 was collected beginning May 1, 2017. The settlement also provides for two additional annual increases of approximately U.S. $0.2 million and $0.3 million effective May 1, 2018 and May 1, 2019, respectively, to recover the revenue requirement associated with certain significant capital investments made during the prior calendar year.

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

Pending Regulatory Proceedings

On October 31, 2017, Empire District Electric Company announced a proposed plan to expand its wind resources with the development of up to an additional 800 MW of strategically located wind generation in or near its service territory by the end of 2020. Once fully operational, the project is projected to generate cost savings for customers of U.S. $172.0 million - U.S. $325.0 million over a twenty-year period. Empire filed a request for approval ("Application") of the wind expansion initiative with regulators in Missouri, Kansas, Oklahoma, and Arkansas, and the project is subject to their respective review. On February 6, 2018, the staff of the Missouri Public Service Commission as well as other intervenors filed testimony responsive to the Application. The staff’s testimony recommends that the Commission should either approve the projects with conditions or rule that it need not provide approval for the projects to proceed, while other intervenors range in their recommendations from suggesting that the Commission not approve the project to recommending outright approvals. Testimony has now also been received in Oklahoma and Arkansas. In Oklahoma both the staff and the Attorney General recommended approval of the projects and in Arkansas additional details were requested on the proposed projects. The Liberty Utilities Group’s local regulatory teams continue to work closely with staffs and commissions from the regulatory agencies and anticipate securing approvals for the projects by June 2018.

CORPORATE DEVELOPMENT ACTIVITIES

The Corporate Development Group works to identify, develop and construct new power generating facilities as well as to identify and acquire operating projects that would be complementary and accretive to the Liberty Power Group’s existing portfolio and the Company as a whole.  The Corporate Development Group is focused on projects within North America and is committed to working proactively with all stakeholders including local communities.

The development and construction of new power generation facilities involves a number of risks and uncertainties including scheduling delays, cost over runs and other events that may be beyond the control of the Company (See Operational Risk Management - Development and Construction Risk).

The Corporate Development Group’s approach to project development and acquisition is to maximize the utilization of internal resources while minimizing external costs. This approach allows projects to mature to the point where most major elements and uncertainties are quantified and resolved prior to the commencement of project construction.  Major elements and uncertainties of a project include the signing of a PPA, obtaining the required financing commitments to develop the project, completion of environmental and other required permitting, and fixing the cost of the major capital components of the project. It is not until all major aspects of a project are secured that the Corporate Development group will begin construction or execute an acquisition agreement.

Each of the projects contained in the table below meet the following criteria: a proven wind or solar resource, a signed PPA with a credit-worthy counterparty, and satisfaction of the Company's investment return objectives. The projects are as follows:

Project Name	Location	Size (MW)	Estimated Capital Cost Range (millions)1					Commercial Operation	PPA Term (Years)	Production (GW-hrs)
Projects in Construction
Amherst Island Wind Project	Ontario	75	$	320	-	$	350	2018	20	235
Great Bay Solar Project2	Maryland	75	169		-	188		2018	10	146
Total Projects in Construction		150	$	489	-	$	538			381
Projects in Development
Blue Hill Wind Project	Saskatchewan	177	$	315	-	$	350	2019/20	25	813
Val-Eo Wind Project3	Quebec	24	60		-	70		2018	20	66
Turquoise Solar Project4	Nevada	10	25		-	31		2018		28
Total Projects in Development		211	$	400	-	$	451			907
Total in Construction and Development		361	$	889	-	$	989			1,288

1	Estimated capital costs for U.S. based projects have been converted at the exchange rate in effect at the end of the current reporting period.
2	The total cost of the project is expected to be approximately U.S. $135 - U.S. $150 million. Two of the four Great Bay Solar sites achieved COD in December 2017 while the remaining two sites are expected to achieve COD in the first quarter of 2018.
3	All figures refer solely to Phase I of the Val-Eo Wind Project.
4	The Turquoise Solar Project will be included in the rate base of the Calpeco Electric System (see Regulatory Proceedings). The total cost of the project is expected to be approximately U.S. $20.0 - U.S. $25.0 million.

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

Projects Completed

Deerfield Wind Project

The Deerfield Wind Project is a 150 MW wind powered electric generating development project located in central Michigan and is constructed on approximately 20,000 acres of land leased from a supportive wind power land owner group.

Construction of the project commenced in the fourth quarter of 2015. The project declared commercial operations on February 21, 2017.

The project is the Liberty Power Group's tenth wind generating facility and consists of 44 Vestas V110-2.0 wind turbines and 28 Vestas V110-2.2 turbines and is estimated to generate 555.2 GW-hrs of energy per year, with all energy, capacity, and renewable energy credits from the project sold to a local electric distribution utility which serves 260,000 customers in Michigan, pursuant to a 20 year PPA.

The Liberty Power Group's initial interest in the project was via a 50% joint venture with the original developer along with an option to acquire the other 50% interest. On March 14, 2017, the Liberty Power Group exercised its option and purchased the remaining 50% interest in the project for U.S. $21.6 million.

The project qualified for U.S. federal production tax credits, and consistent with financing structures utilized for U.S. based renewable energy projects, approximately U.S. $166.6 million of financing for the project was received from tax equity investors in May 2017.

Bakersfield II Solar Project

The Bakersfield II Solar Project is a 10 MWac solar powered electric generating project adjacent to the Liberty Power Group's 20 MW Bakersfield I Solar Project in Kern County, California.

Construction of the project commenced in the second quarter of 2015. The facility declared commercial operations on January 11, 2017.

The facility is the Liberty Power Group's third solar generating facility and is comprised of approximately 38,640 solar panels located on 64 acres of land. The project is expected to generate 24.2 GW-hrs of energy per year which is being sold under a 20 year PPA with a large investment grade electric utility.

The project qualified for U.S. federal investment tax credits, and consistent with financing structures utilized for U.S. based renewable energy projects, approximately U.S. $12.3 million of financing for the project was sourced from a tax equity investor. The tax equity financing closed on February 28, 2017, following achievement of commercial operations.

Projects in Construction

Amherst Island Wind Project

The Amherst Island Wind Project is a 75 MW wind powered electric generating development project located on Amherst Island near the village of Stella, approximately 15 kilometers southwest of Kingston, Ontario.

The project is currently contemplated to use Class III wind turbine generator technology consisting of 26 Siemens 3.0 MW turbines and is expected to produce approximately 235.0 GW-hrs of electrical energy annually, with all energy being sold under a 20 year PPA awarded as part of the Independent Electricity System Operator ("IESO"), formerly the Ontario Power Authority, Feed in Tariff ("FIT") program.

Liberty Power's interest in the project is via a 50% joint venture. Liberty Power has an option to acquire the other 50% interest, subject to certain adjustments, after COD and prior to January 15, 2019.

The total costs to complete the project are estimated at approximately $320.0 million to $350.0 million. The increase in the expected range of construction costs are primarily the result of additional winter construction days than previously anticipated. As the Company refines its operating model for post COD, it has identified new operational costs savings of approximately $10.0 million which are expected to be realized over the life of the project. Construction over the fall and winter months has focused primarily on building access roads, foundations and receiving turbine components.

Manufacturing of major equipment is now complete and turbine deliveries commenced in November 2017, with all turbines expected to be delivered by March 2018. To date, two turbines have been erected and the foundation for the power transformer housing is complete. The main power transformer was delivered to the site in early February 2018. A 115kV submarine cable was also successfully installed during 2017. Subject to receipt of ongoing construction-related permitting, construction is expected to be substantially completed in the second quarter of 2018.

Placement of construction debt closed in the fourth quarter of 2017 with a consortium of major financial institutions for a total commitment of $260.4 million.

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

Great Bay Solar

The Great Bay Solar Project is a 75 MWac solar powered electric generating development project comprised of four sites located in Somerset County in southern Maryland.

The facility is comprised of 300,000 solar panels and is being constructed on 400 acres of land. The project is expected to generate 146.0 GW-hrs of energy per year, with all energy sold to the U.S. Government Services pursuant to a 10 year PPA, with a 10 year extension option. All Solar Renewable Energy Credits from the project will be retained by the project company and sold into the Maryland market.

The project received its Certificate of Public Convenience and Necessity from the State of Maryland Public Service Commission and building permits from the Somerset County Building and Zoning Department. Both the balance of plant and high voltage engineering, procurement, and construction contracts have been executed.

The total costs to complete the project are estimated at approximately U.S. $135.0 million to U.S. $150.0 million. The project achieved partial completion in late 2017, producing revenue on 25 MW of the full site capacity. Approximately U.S. $59.0 million of the permanent project financing will come from tax equity investors. As of December 31, 2017, the project has received U.S $42.8 million in project funding, with the remaining expected to be received in the first half of 2018.

Projects in Development

Blue Hill Wind Project

The Blue Hill Wind Project is a 177 MW wind powered electric generating development project located in the rural municipalities of Lawtonia and Morse in southwest Saskatchewan.

The project is expected to generate 813.0 GW-hrs of energy per year, with all energy sold to SaskPower pursuant to a 25 year PPA originally awarded in 2012 and amended in 2016.

The project requires development permits as well as final environmental approval. The Environmental Impact Study was completed and submitted to the Saskatchewan Ministry of Environment in the fourth quarter of 2017. Stakeholder engagement continued through 2017 with relevant government officials, NGOs, landowners and the community through open houses and in-person meetings.

The total costs to complete the project are estimated at approximately $315.0 million to $350.0 million. SaskPower recently completed an interim system impact study for the wind turbine generators, which was received in the fourth quarter of 2017. A geotechnical evaluation of the project site and existing infrastructure began in the fourth quarter of 2017, with results expected in early 2018. Preparation and submission of the development permit is expected in the first quarter of 2018.

Val-Éo Wind Project

The Val-Éo Wind Project is a 125 MW wind powered electric generating development project located in the local municipality of Saint-Gideon de Grandmont, which is within the regional municipality of Lac-Saint-Jean-Est, Quebec. The project proponents include the Val-Éo Wind Cooperative which was formed by community based landowners and the Liberty Power Group.

The Liberty Power Group has a 50% economic equity interest in the project. It is believed that the first 24 MW phase of the Val-Éo Wind Project will qualify as Canadian Renewable Conservation Expense and, therefore, the project will be entitled to a refundable tax credit equal to approximately $16.0 million.

The project will be developed in two phases: Phase I of the project is expected to be completed in 2018 and will likely comprise ten 2.35 MW wind turbines for a total capacity of 24 MW and is expected to generate 66.0 GW-hrs of energy per year, with all energy from Phase I of the project to be sold to Hydro-Quebec pursuant to a 20 year PPA; Phase II of the project would entail the development of an additional 101 MW and would be constructed following the successful evaluation of the wind resource at the site, completion of satisfactory permitting and entering into appropriate energy sales arrangements.

The total costs to complete Phase I of the project are estimated at approximately $60.0 million to $70.0 million. All land agreements, construction permits, and authorizations have been obtained for Phase I. The new schedule calls for Phase I construction to begin in the second quarter of 2018, with commissioning to occur in the fourth quarter of 2018.

Turquoise Solar Project

The Turquoise Solar project is a 10 MW solar powered electric generating development project located in Washoe County in Nevada.

The facility is comprised of 108,000 solar thin film panels on a tracker system and is being constructed on 110 acres of land. The Turquoise Solar Project is expected to generate 28 GW-hrs of energy per year and to be included in the rate base of the Calpeco Electric System as energy produced from the project will be consumed by the utility's customers (see Regulatory Proceedings).

The project has been approved by the California PUC, and mechanical completion is expected in the fourth quarter of 2018.

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

The total costs to complete the project are estimated at approximately U.S. $20.0 million to U.S. $25.0 million. The Liberty Utilities Group expects the project will qualify for U.S. federal investment tax credits and accordingly, approximately 30% of the permanent financing is expected to be funded by tax equity investors.

APUC: CORPORATE AND OTHER EXPENSES

	Three Months Ended December 31						Twelve Months Ended December 31
(all dollar amounts in $ millions)	2017			2016			2017			2016
Corporate and other expenses:
Administrative expenses	$	18.7		$	13.1		$	64.5		$	46.3
(Gain)/Loss on foreign exchange	1.6			1.3			0.4			(0.4		)
Interest expense on convertible debentures and acquisition facility related to the Empire Acquisition	—			18.2			17.6			57.6
Interest expense	42.4			20.5			185.0			74.0
Interest, dividend, equity, and other income1	(0.6		)	(3.1		)	(2.8		)	(5.3		)
Other losses (gains)	4.7			(0.8		)	0.6			(11.8		)
Acquisition-related costs	1.3			2.4			62.8			12.0
Loss (gain) on derivative financial instruments	(4.0		)	(12.9		)	(2.6		)	(15.8		)
Income tax expense	38.0			11.5			95.2			37.1

1 Excludes income directly pertaining to the Liberty Power and Liberty Utilities Groups (disclosed in the relevant sections).

U.S. Tax Reform

On December 22, 2017, H.R. 1, the Tax Cuts and Jobs Act (“U.S. Tax Reform” or the “Act”), was signed into law which resulted in significant changes to U.S. tax law. Key provisions of U.S. Tax Reform include the following:

• U.S. federal corporate income tax rate reduction from 35 per cent to 21 per cent effective January 1, 2018.

• The corporate alternative minimum tax (“AMT”) is eliminated effective January 1, 2018.

• The Base Erosion Anti-Abuse Tax (“BEAT”) is a new minimum tax computed each year and is generally the excess of (a) 10% of the taxpayer’s "modified taxable income" over (b) the taxpayer’s regular tax liability reduced by its tax credits.

• Other than for regulated utilities, interest deductibility is limited to 30 per cent of EBITDA from 2018 to 2021 and 30 per cent of EBIT after 2021.

• Other than for regulated utilities, immediate expensing of 100 per cent of the cost of new investments made in qualified depreciable assets after September 27, 2017.

• The production tax credit (the "PTC") of Section 45 of the Code and the investment tax credit (the "ITC") of Section 48 of the Code are left unchanged by the Act and the elimination of the AMT ensures that renewable energy tax credits will continue to be valuable to tax equity investors.

• The Act allows taxpayers until 2025 to offset any tax owed under the BEAT by 80% of the value of the PTCs and the ITCs for renewable energy projects.

• No change was made to the "continuous construction" requirement for determining when construction of a project commences.

As a result of these changes, the Company has remeasured existing deferred income tax assets and deferred income tax liabilities related to our U.S. regulated and non-regulated businesses to reflect the new lower income tax rate as at December 31, 2017. This remeasurement resulted in a one-time non-cash accounting charge of $22.4 million and is recorded in the Company’s 2017 consolidated statement of operations.

Future Impacts

Beginning in 2018, the Company expects its effective tax rate on consolidated worldwide net income to be below 20%.

The Company expects that the effects of U.S. Tax Reform in 2018 will be neutral to slightly positive to EPS and approximately 2%-3% negative to 2018 EBITDA, which is within the planning parameters that APUC establishes for normal variability in its business cycle from wind, hydrology and weather.

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

The Company believes that most of its U.S. holding company interest can be properly allocable in accordance with the Act to its U.S. regulated utilities and is therefore largely exempted from the interest deductibility limitations.

It is expected there will be no material changes to the Company’s U.S. regulated utilities’ future net earnings, specifically as it pertains to U.S. Tax Reform since normal rate making processes would see the lower income tax expense and amortization of the deferred tax revaluation regulatory liability offset by lower customer rates over time. However, the Company believes that all stakeholders are best served by dealing with U.S. Tax Reform within the context of a full regulatory rate case proceeding, where all factors that comprise rates can be considered including investments in rate base, recovery of operating costs, capital structure and cost of capital.

APUC views that going forward the lower tax rates can enable accelerated investment over time in our regulated utilities to deliver an improved customer experience and more reliable service with less of an impact on customer rates than would otherwise occur.

APUC continues to believe that with the provisions in the Act for PTCs and ITCs, between the Company’s ability to absorb a part of the renewable energy tax credits in future years and anticipated future demand from third party tax equity investors wishing to avail themselves of renewable energy tax credits, the Company will be able to satisfy the tax equity financing component for its U.S. renewable energy projects over the next three to five years.

SEC Guidance

The U.S. Securities and Exchange Commission (“SEC”) has issued guidance allowing registrants to record provisional amounts which may be adjusted as information over time becomes available, prepared or analyzed during a measurement period not to exceed one year.

The SEC guidance summarizes a three-step process to be applied at each reporting period to identify: (1) where the accounting is complete; (2) provisional amounts where the accounting is not yet complete, but a reasonable estimate has been determined; and (3) where a reasonable estimate cannot yet be determined and therefore income taxes are reflected in accordance with tax laws in effect prior to the enactment of the Act.

At December 31, 2017, APUC considers all amounts recorded related to U.S. Tax Reform to be reasonable estimates. Given that APUC’s utility businesses are regulated, the Company’s interpretation, assessment and presentation of the impact of U.S. Tax Reform may be further clarified with additional guidance from regulatory, tax and accounting authorities. Should additional information emerge that affects current estimates during this one-year measurement period allowed for by the SEC, adjustments will be made to the provisional amounts as appropriate.

2017Fourth Quarter Corporate and Other Expenses

During the three months ended December 31, 2017, administrative expenses totaled $18.7 million as compared to $13.1 million in the same period in 2016. The $5.6 million increase primarily relates to additional costs incurred to administer APUC's operations as a result of the Company's growth, including ongoing administration expenses related to Empire.

For the three months ended December 31, 2017, interest expense on convertible debentures and bridge financing totaled $nil as compared to $18.2 million in the same period in 2016.

For the three months ended December 31, 2017, interest expense totaled $42.4 million as compared to $20.5 million in the same period in 2016. The interest expense for the period is primarily attributable to assumed and incremental debt related to the Empire Acquisition, and new debt raised by the Liberty Power and Liberty Utilities Groups.

For the three months ended December 31, 2017, other losses were $4.7 million as compared to gains of $0.8 million in the same period in 2016. The increase in current period losses is primarily attributable to an increase in regulatory liabilities in the LPSCo Water System resulting from ongoing regulatory proceedings.

For the three months ended December 31, 2017, gains on derivative financial instruments totaled $4.0 million as compared to $12.9 million in the same period in 2016. The increase in 2016 was primarily driven by mark-to-market gains on foreign currency derivatives.

For the three months ended December 31, 2017, an income tax expense of $38.0 million was recorded as compared to an income tax expense of $11.5 million during the same period in 2016. The increase in income tax expense is primarily due to the Empire Acquisition and a one-time non-cash accounting charge of $22.4 million related to the revaluation of the Company's U.S. non-regulated net deferred income tax assets as a result of U.S. Tax Reform (see U.S. Tax Reform for additional information).

Algonquin Power & Utilities Corp. - Management Discussion & Analysis 33

2017 Annual Corporate and Other Expenses

During the twelve months ended December 31, 2017, administrative expenses totaled $64.5 million as compared to $46.3 million in the same period in 2016. The increase primarily relates to additional costs incurred to administer APUC's operations as a result of the Company's growth, including ongoing administration expenses related to Empire.

For the twelve months ended December 31, 2017, interest expense on convertible debentures and bridge financing totaled $17.6 million as compared to $57.6 million in the same period in 2016 (see note 14 in the financial statements).

For the twelve months ended December 31, 2017, interest expense totaled $185.0 million as compared to $74.0 million in the same period in 2016. The increase in interest expense for the period is primarily attributable to assumed and incremental debt related to the Empire Acquisition, and new debt raised by the Liberty Power and Liberty Utilities Groups. (See Credit Facilities & Debt and note 9 in the financial statements).

For the twelve months ended December 31, 2017, other losses were $0.6 million as compared to a gain of $11.8 million in the same period in 2016. The prior period gains primarily resulted from: (i) the recognition of deferred income on repairs completed for facilities where the insurance proceeds have been received in advance; and (ii) the settlement of litigation and bankruptcy proceedings relating to Trafalgar Power Inc. (see note 18 in the financial statements) partially offset by (iii) the write-down of the Company's equity interest in natural gas development projects that have been canceled by the developer.

For the twelve months ended December 31, 2017, acquisition-related costs totaled $62.8 million as compared to $12.0 million in the same period in 2016. The increase is primarily attributable to the Empire Acquisition.

For the twelve months ended December 31, 2017, the gain on derivative financial instruments totaled $2.6 million as compared to a gain of $15.8 million in the same period in 2016. The gain in 2016 was due to market-to-market gains on foreign currency hedges offset by losses on the ineffective portion of derivative financial instruments accounted for as derivatives.

An income tax expense of $95.2 million was recorded in the twelve months ended December 31, 2017 as compared to an income tax expense of $37.1 million during the same period in 2016. The increase in income tax expense is primarily due to the Empire Acquisition, the tax effect related to the Mountain Water condemnation, and a one-time non-cash accounting charge of $22.4 million related to the revaluation of the Company's U.S. non-regulated net deferred income tax assets as a result of U.S. Tax Reform (see U.S. Tax Reform for additional information).

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

NON-GAAP FINANCIAL MEASURES

Reconciliation of Adjusted EBITDA to Net Earnings

The following table is derived from and should be read in conjunction with the consolidated statement of operations. This supplementary disclosure is intended to more fully explain disclosures related to Adjusted EBITDA and provides additional information related to the operating performance of APUC. Investors are cautioned that this measure should not be construed as an alternative to U.S. GAAP consolidated net earnings.

	Three Months Ended December 31						Twelve Months Ended December 31
(all dollar amounts in $ millions)	2017			2016			2017			2016
Net earnings attributable to shareholders	$	60.0		$	46.3		$	193.1		$	130.9
Add (deduct):
Net earnings attributable to the non-controlling interest, exclusive of HLBV	0.8			(0.8		)	3.2			7.5
Income tax expense	38.0			11.5			95.2			37.1
Interest expense on convertible debentures and bridge financing	—			18.2			17.6			57.6
Interest expense on long-term debt and others	42.4			20.5			185.0			74.0
Other losses (gains)	4.8			(0.8		)	0.7			(11.9		)
Acquisition-related costs	1.3			2.4			62.8			12.0
Costs related to tax equity financing	0.5			—			2.3			—
Loss (gain) on derivative financial instruments	(4.0		)	(12.9		)	(2.6		)	(15.8		)
Realized loss on energy derivative contracts	—			—			(0.7		)	(1.0		)
Loss (gain) on foreign exchange	1.6			1.3			0.4			(0.4		)
Depreciation and amortization	88.0			52.6			326.4			186.9
Adjusted EBITDA	$	233.4		$	138.3		$	883.4		$	476.9

HLBV represents the value of net tax attributes earned during the period primarily from electricity generated by certain U.S. wind power and U.S. solar generation facilities. HLBV earned in the three and twelve months ended December 31, 2017 amounted to $14.3 million and $67.8 million as compared to $13.6 million and $41.0 million during the same period in 2016.

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

Reconciliation of Adjusted Net Earnings to Net Earnings

The following table is derived from and should be read in conjunction with the consolidated statement of operations. This supplementary disclosure is intended to more fully explain disclosures related to Adjusted Net Earnings and provides additional information related to the operating performance of APUC. Investors are cautioned that this measure should not be construed as an alternative to consolidated net earnings in accordance with U.S. GAAP.

The following table shows the reconciliation of net earnings to Adjusted Net Earnings exclusive of these items:

	Three Months Ended December 31						Twelve Months Ended December 31
(all dollar amounts in $ millions)	2017			2016			2017			2016
Net earnings attributable to shareholders	$	60.0		$	46.3		$	193.1		$	130.9
Add (deduct):
Loss (gain) on derivative financial instruments	(4.0		)	(12.9		)	(2.6		)	(15.8		)
Realized loss on derivative financial instruments	—			—			(0.7		)	(1.0		)
Loss (gain) on long-lived assets, net	1.5			(0.8		)	(2.5		)	(3.3		)
Loss (gain) on foreign exchange	1.6			1.3			0.4			(0.4		)
Interest expense on convertible debentures and acquisition financing	—			18.2			17.6			57.6
Acquisition-related costs	1.3			2.4			62.8			12.0
Costs related to tax equity financing	0.5			—			2.3			—
Other adjustments	3.2			—			3.2			—
U.S. Tax Reform adjustment 2	22.4						22.4
Adjustment for taxes related to above	(0.6		)	(3.1		)	(3.9		)	(18.4		)
Adjusted Net Earnings	$	85.9		$	51.4		$	292.1		$	161.6
Adjusted Net Earnings per share1	$	0.20		$	0.18		$	0.74		$	0.57

1	Per share amount calculated after preferred share dividends and excluding subscription receipts issued for projects or acquisitions not reflected in earnings.
2	Represents the one-time non-cash accounting charge related to the revaluation of U.S. non-regulated net deferred income tax assets as a result of U.S. Tax Reform (see U.S. Tax Reform for additional information).

For the three months ended December 31, 2017, Adjusted Net Earnings totaled $85.9 million as compared to Adjusted Net Earnings of $51.4 million for the same period in 2016, an increase of $34.5 million. The increase in Adjusted Net Earnings for the three months ended December 31, 2017 is primarily due to increased earnings from operations partially offset by higher depreciation and amortization expense as compared to 2016.

For the twelve months ended December 31, 2017, Adjusted Net Earnings totaled $292.1 million as compared to Adjusted Net Earnings of $161.6 million for the same period in 2016, an increase of $130.5 million. The increase in Adjusted Net Earnings for the twelve months ended December 31, 2017 is primarily due to increased earnings from operations partially offset by higher depreciation and amortization expense as compared to 2016.

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

Reconciliation of Adjusted Funds from Operations to Cash Flows from Operating Activities

The following table is derived from and should be read in conjunction with the consolidated statement of operations and consolidated statement of cash flows. This supplementary disclosure is intended to more fully explain disclosures related to Adjusted Funds from Operations and provides additional information related to the operating performance of APUC. Investors are cautioned that this measure should not be construed as an alternative to funds from operations in accordance with U.S GAAP.

The following table shows the reconciliation of funds from operations to Adjusted Funds from Operations exclusive of these items:

	Three Months Ended December 31						Twelve Months Ended December 31
(all dollar amounts in $ millions)	2017			2016			2017		2016
Cash flows from operating activities	$	169.8		$	121.9		$	457.8	$	287.9
Add (deduct):
Changes in non-cash operating items	(12.0		)	(46.7		)	74.0		(3.7		)
Production based cash contributions from non-controlling interests	—			0.6			10.6		11.2
Interest expense on convertible debentures and acquisition financing fees1	—			18.2			9.3		57.6
Acquisition-related costs	1.3			2.4			62.8		12.0
Cash generated from sale of long-lived assets	—			—			—		(8.6		)
Adjusted Funds from Operations	$	159.1		$	96.4		$	614.5	$	356.4

¹  Exclusive of deferred financing fees of $8.3 million.

For the three months ended December 31, 2017, Adjusted Funds from Operations totaled $159.1 million as compared to Adjusted Funds from Operations of $96.4 million for the same period in 2016, an increase of $62.7 million.

For the twelve months ended December 31, 2017, Adjusted Funds from Operations totaled $614.5 million as compared to Adjusted Funds from Operations of $356.4 million for the same period in 2016, an increase of $258.1 million.

SUMMARY OF PROPERTY, PLANT, AND EQUIPMENT EXPENDITURES ¹ 

	Three Months Ended December 31				Twelve Months Ended December 31
(all dollar amounts in $ millions)	2017		2016		2017		2016
Liberty Power Group:
Maintenance	$	4.0	$	21.0	$	18.1	$	58.6
Investment in Capital Projects1	17.1		169.0		592.7		538.1
	$	21.1	$	190.0	$	610.8	$	596.7
Liberty Utilities Group:
Rate Base Maintenance	$	58.4	$	27.0	$	222.1	$	102.7
Rate Base Acquisition	—		—		2,764.4		345.3
Rate Base Growth	89.8		101.0		328.7		163.4
	148.2		128.0		3,315.2		611.4
Total Capital Expenditures	$	169.3	$	318.0	$	3,926.0	$	1,208.1

1 Includes expenditures on Property Plant & Equipment, equity-method investees, and acquisitions of operating entities that were jointly developed by the Company.

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

2017Fourth Quarter Property Plant and Equipment Expenditures

During the three months ended December 31, 2017, the Liberty Power Group incurred capital expenditures of $21.1 million as compared to $190.0 million during the same period in 2016. The capital expenditures include the ongoing construction of the Great Bay Solar Project, additional investment into the Amherst Wind Project, and ongoing maintenance capital at existing operating sites. Capital expenditures in the same quarter last year included the purchase of approximately $75 million of turbine components ("Safe Harbor Turbines"), costs of rebuilding the Donnaconna Hydro Facility dam, and ongoing development costs related to the investment and build of the Deerfield Wind, Amherst Wind, and Great Bay Solar Projects.

During the three months ended December 31, 2017, the Liberty Utilities Group invested $148.2 million in capital expenditures as compared to $128.0 million during the same period in 2016. The Liberty Utilities Group’s investment was primarily related to reliability enhancements, improvements and replenishment opportunities, and leak prone pipe replacements, leak repairs and pipeline corrosion protection initiatives relating to safety and reliability at the electric and gas systems. Capital expenditures in the same quarter last year included investments into the Luning Solar Facility and further development of Phase I of the North Lake Tahoe transmission project to upgrade the 650 Line (10 miles) which runs from Northstar to Kings Beach, California to 120kV.

2017 Annual Property Plant and Equipment Expenditures

During the twelve months ended December 31, 2017, the Liberty Power Group incurred capital expenditures of $610.8 million as compared to $596.7 million during the same period in 2016. The capital expenditures include the acquisition of the remaining outstanding interest in the Deerfield Wind Facility, completion of the Bakersfield II Solar Facility, upgrade of the Tinker Transmission Facility, and ongoing development costs related to the investment and construction of the Amherst Wind and Great Bay Solar Projects.

During the twelve months ended December 31, 2017, the Liberty Utilities Group invested $3.3 billion in capital expenditures as compared to $611.4 million during the same period in 2016. The increase in capital expenditures is primarily due to the Empire Acquisition in January 2017 (U.S. $2.4 billion) and completion of the Luning Solar Facility located in Mineral County, Nevada in February 2017 (U.S. $84.9 million). In the prior year, the Liberty Utilities Group completed the acquisition of the Park Water System in January 2016, further development of Phase I of the North Lake Tahoe transmission project, and reliability enhancements, improvements and replenishment opportunities at the utility systems served.

2018 Capital Investments

In 2018, the Company plans to spend between $1.2 billion and $1.4 billion on capital investment opportunities. Actual expenditures during the course of 2018 may vary due to timing of various project investments and the realized U.S. dollar exchange rate.

Expected 2018 capital investment ranges are as follows:

(all dollar amounts in $ millions)
Liberty Power Group:
Maintenance	$	30.0	-	$	40.0
Investment in Capital Projects	120.0		-	150.0
Total Liberty Power Group:	$	150.0	-	$	190.0
Liberty Utilities Group:
Rate Base Maintenance	$	210.0	-	$	230.0
Rate Base Growth	140.0		-	180.0
Total Liberty Utilities Group:	$	350.0	-	$	410.0
Investment in Atlantica1	$	700.0		$	800.0
Total 2018 Capital Investments	$	1,200.0	-	$	1,400.0

¹  See Major Highlights

The Liberty Power Group intends to spend between $150.0 million - $190.0 million over the course of 2018 to develop or further invest in capital projects, primarily in relation to the final development of the Great Bay Solar and Amherst Island Wind Projects. Additionally, the Liberty Power Group plans to spend $30.0 million - $40.0 million on various operational solar, thermal, and wind assets to maintain safety, regulatory, and operational efficiencies.

The Liberty Utilities Group intends to spend between $350.0 million - $410.0 million over the course of 2018 in an effort to improve the reliability of the utility systems and broaden the technologies used to better serve its service areas. Projects

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

entail spending capital for structural improvements, specifically in relation to drilling and equipping aquifers, main replacements, and reservoir pumping stations.

LIQUIDITY AND CAPITAL RESERVES

APUC has revolving credit and letter of credit facilities available for Corporate, the Liberty Power Group, and the Liberty Utilities Group to manage the liquidity and working capital requirements of each division (collectively the “Bank Credit Facilities”).

Bank Credit Facilities

The following table sets out the Bank Credit Facilities available to APUC and its operating groups as at December 31, 2017:

	As at December 31, 2017												As at Dec 31, 2016
(all dollar amounts in $ millions)	Corporate			Liberty Power			Liberty Utilities			Total			Total
Committed facilities	$	165.0		$	714.9		$	501.8		$	1,381.7		$	773.8
Funds drawn on facilities	—			(44.8		)	(16.3		)	(61.1		)	(242.9		)
Letters of credit issued	(13.9		)	(136.3		)	(24.5		)	(174.7		)	(234.9		)
Liquidity available under the facilities	151.1			533.8			461.0			1,145.9			296.0
Cash on hand										54.6			110.4
Total Liquidity and Capital Reserves	$	151.1		$	533.8		$	461.0		$	1,200.5		$	406.4

As at December 31, 2017, the Company's $165.0 million senior unsecured revolving credit facility (the "Corporate Credit Facility") was undrawn and had $13.9 million of outstanding letters of credit. The facility matures on November 19, 2018 and is subject to customary covenants.

On December 21, 2017, the Company entered into a U.S. $600.0 million term credit facility with two Canadian banks maturing on December 21, 2018. The proceeds of the term credit facility provide the company with additional liquidity for general corporate purposes and acquisitions. On March 7, 2018 the company drew U.S. $600.0 million under this facility.

As at December 31, 2017, the Liberty Power Group's committed bank lines consisted of a U.S. $500.0 million senior unsecured syndicated revolving credit facility and a $87.6 million letter of credit facility (Cdn $50.0 million and U.S. $30.0 million). As at December 31, 2017, the group had drawn $44.8 million and had $136.3 million in outstanding letters of credit. The facilities mature on October 6, 2022 and October 30, 2018, respectively. Subsequent to year-end, on February 16, 2018, the Liberty Power Group increased availability under its revolving letter of credit facility to U.S. $200.0 million and extended the maturity to January 31, 2021. The expansion of both the revolving credit and letter of credit facility further increases the Liberty Power Group's ability to support the cash needs of its development portfolio.

As at December 31, 2017, the Liberty Utilities Group's committed bank lines consisted of a U.S. $200.0 million senior unsecured syndicated revolving credit facility at the holding company ("Liberty Credit Facility") and a U.S. $200.0 million revolving credit facility at Empire ("Empire Credit Facility"). The credit facilities mature on September 30, 2018 and October 20, 2019, respectively. The Empire Credit Facility is used primarily as a backstop to commercial paper issued by Empire. As at December 31, 2017, the Liberty Utilities Grouphad drawn a total of $16.3 million (U.S. $13.0 million) and had $24.5 million (U.S. $19.5 million) of outstanding letters of credit. Subsequent to year-end on February 23, 2018, the Liberty Utilities Group increased commitments under the Liberty Credit Facility to U.S. $500.0 million and extended the maturity to 2023. In conjunction with the increase to the Liberty Credit Facility, the Empire Credit Facility was canceled. The Liberty Credit Facility will now be used as a backstop for Empire's commercial paper program and as a source of liquidity for Empire as required.

On February 9, 2016, in connection with the Empire Acquisition, the Company obtained U.S. $1.6 billion in acquisition financing commitments ("Acquisition Facility") from a syndicate of banks. On December 30, 2016, the Company drew U.S. $1,336.4 million on the Acquisition Facility in connection with the closing of the Empire Acquisition. The Acquisition Facility was fully repaid in the first quarter of 2017 from proceeds received from the final installment payment, the Liberty Private Placement (discussed below) and general corporate funds.

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

Long Term Debt

On January 17, 2017, the Liberty Power Group issued $300.0 million of senior unsecured debentures bearing interest at 4.09% with a maturity date of February 17, 2027. The debentures were sold at a price of $99.929 per $100.00 principal amount. Concurrent with the offering, the Liberty Power Group entered into a cross currency swap, coterminous with the debentures, to economically convert the Canadian dollar denominated offering into U.S. dollars for an effective yield of 4.86%.

On March 24, 2017, the Liberty Utilities Group's financing entity issued U.S. $750.0 million of senior unsecured notes ("Liberty Private Placement") in the U.S. and Canada. The notes are of varying maturities from 3 to 30 years with a weighted average life of approximately 15 years and a weighted average coupon of 4.0%. In anticipation of the financing, Liberty Utilities had entered into forward contracts to lock in the underlying U.S. Treasury interest rates (see "Interest Rate Risk"). Considering the effect of the hedges, the effective weighted average rate paid by the Liberty Utilities Group is 3.6%. The proceeds of the offering were applied to repay the balance of the Acquisition Facility and other existing indebtedness.

As at December 31, 2017, the weighted average tenor of APUC's total long term debt is approximately 12 years with an average interest rate of 4.6%.

Convertible Unsecured Subordinated Debentures

In the first quarter of 2016, in connection with the Empire Acquisition, APUC and its direct wholly-owned subsidiary, Liberty Utilities (Canada) Corp., entered into an agreement with a syndicate of underwriters under which the underwriters agreed to buy, on a bought deal basis, $1.15 billion aggregate principal amount of 5.00% convertible unsecured subordinated debentures of APUC.

All Debentures were sold on an instalment basis at a price of $1,000 dollars per debenture, of which $333 dollars was paid on the closing of the Offering and the remaining $667 dollars was payable on a date set by APUC upon satisfaction of all conditions precedent to the closing of the Empire Acquisition (the "Final Instalment Date"), at which time each debenture was convertible to 94.3396 common shares of APUC and bears an interest rate of 0% thereafter.

The final instalment date was established as February 2, 2017, at which time APUC received the final instalment payment. The proceeds were used to repay a portion of the Acquisition Facility. As at March 6, approximately 99.9% of the Debentures have been converted into common shares of APUC, with APUC issuing approximately 108,384,716 common shares as a result of the conversion.

Credit Ratings

APUC has a long term consolidated corporate credit rating of BBB (flat) from Standard & Poor's ("S&P") and a BBB (low) rating from DBRS Limited ("DBRS"). Algonquin Power Co ("APCo"), the parent company for the Liberty Power Group, has a BBB (flat) issuer rating from S&P and BBB (low) issuer rating from DBRS. Liberty Utilities Finance GP1 ("Liberty Finance"), a special purpose financing entity of Liberty Utilities Co., the parent company for the Liberty Utilities Group, has a BBB (high) issuer rating from DBRS. Empire has a BBB rating from S&P and a Baa1 rating from Moody's Investors Service, Inc. ("Moody's").

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

Contractual Obligations

Information concerning contractual obligations as of December 31, 2017 is shown below:

(all dollar amounts in $ millions)	Total		Due less than 1 year		Due 1 to 3 years		Due 4 to 5 years		Due after 5 years
Principal repayments on debt obligations1	$	3,826.1	$	279.7	$	570.1	$	645.0	$	2,331.3
Convertible debentures	1.2		—		—		—		1.2
Advances in aid of construction	78.6		1.5		—		—		77.1
Interest on long-term debt obligations	2,006.2		172.7		307.5		250.8		1,275.2
Purchase obligations	501.9		501.9		—		—		—
Environmental obligations	72.0		7.8		18.9		5.4		39.9
Derivative financial instruments:
Cross currency swap	72.0		4.4		8.1		64.7		(5.2		)
Interest rate swap	10.6		10.6		—		—		—
Currency forward	0.4		0.4		—		—		—
Energy derivative and commodity contracts	3.4		2.3		1.0		—		0.1
Purchased power	527.4		74.0		98.3		100.7		254.4
Gas delivery, service and supply agreements	369.2		91.4		118.7		61.6		97.5
Service agreements	673.9		47.7		95.7		95.4		435.1
Capital projects	58.3		41.1		17.1		0.1		—
Operating leases	270.0		9.6		17.3		18.1		225.0
Other obligations	155.3		45.0		—		—		110.3
Total Obligations	$	8,626.5	$	1,290.1	$	1,252.7	$	1,241.8	$	4,841.9

1 Exclusive of deferred financing costs, bond premium/discount, fair value adjustments at the time of issuance or acquisition.

Equity

The common shares of APUC are publicly traded on the Toronto Stock Exchange (“TSX”) and the New York Stock Exchange ("NYSE") under the trading symbol "AQN".  As at December 31, 2017, APUC had 431,765,935 issued and outstanding common shares.

APUC 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 APUC upon liquidation, dissolution or winding up of APUC.  All shares are of the same class and with equal rights and privileges and are not subject to future calls or assessments.

On November 10, 2017, APUC announced that it closed a bought deal offering announced on November 1, 2017, including the exercise in full of the underwriters' over-allotment option. As a result a total of 43,470,000 common shares of APUC were sold at a price of $13.25 per share for gross proceeds of approximately $576.0 million.

Net proceeds of the offering are expected to be used, in part, to finance APUC's acquisition of a 25% ownership stake in Atlantica from Abengoa and for general corporate purposes.

APUC is also authorized to issue an unlimited number of preferred shares, issuable in one or more series, containing terms and conditions as approved by the Board.  As at December 31, 2017, APUC had outstanding:

• 4,800,000 cumulative rate reset Series A preferred shares, yielding 4.5% annually for the initial six-year period ending on December 31, 2018;

• 100 Series C preferred shares that were issued in exchange for 100 Class B limited partnership units by St. Leon Wind Energy LP; and

• 4,000,000 cumulative rate reset Series D preferred shares, yielding 5.0% annually for the initial five year period ending on March 31, 2019.

APUC has a shareholder dividend reinvestment plan (the “Reinvestment Plan”) for registered holders of common shares of APUC. As at December 31, 2017, 94,049,616 common shares representing approximately 22% of total common shares outstanding had been registered with the Reinvestment Plan. During the year ended December 31, 2017, 3,905,848 common

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

shares were issued under the Reinvestment Plan, and subsequent to year-end, on January 12, 2018, an additional 1,063,572 common shares were issued under the Reinvestment Plan.

SHARE-BASED COMPENSATION PLANS

For the twelve months ended December 31, 2017, APUC recorded $10.8 million in total share-based compensation expense as compared to $5.7 million for the same period in 2016. There is no tax benefit associated with the share-based compensation expense. The compensation expense is recorded as part of administrative expenses in the consolidated statement of operations. The portion of share-based compensation costs capitalized as cost of construction is insignificant.

As at December 31, 2017, total unrecognized compensation costs related to non-vested options and share unit awards were $2.8 million and $8.5 million, respectively, and are expected to be recognized over a period of 1.61 and 1.84 years, respectively.

Stock Option Plan

APUC has a stock option plan that permits the grant of share options to key officers, directors, employees and selected service providers. Except in certain circumstances, the term of an option shall not exceed ten (10) years from the date of the grant of the option.

APUC determines the fair value of options granted using the Black-Scholes option-pricing model.  The estimated fair value of options, including the effect of estimated forfeitures, is recognized as expense on a straight-line basis over the options’ vesting periods while ensuring that the cumulative amount of compensation cost recognized at least equals the value of the vested portion of the award at that date. During the twelve months ended December 31, 2017, the Company granted 2,328,343 options to executives of the Company. The options allow for the purchase of common shares at a weighted average price of $12.82, the market price of the underlying common share at the date of grant. In March 2017, executives of the Company exercised 1,469,362 stock options at a weighted average exercise price of $7.81 in exchange for common shares issued from treasury and 165,139 options were settled at their cash value as payment for tax withholdings related to the exercise of the options.

As at December 31, 2017, a total of 6,738,856 options are issued and outstanding under the stock option plan.

Performance Share Units

APUC issues performance share units (“PSUs”) to certain members of management as part of APUC’s long-term incentive program.  During the twelve months ended December 31, 2017, the Company granted (including dividends and performance adjustments) 811,974 PSUs to executives and employees of the Company. During the year, the Company settled 374,973 PSUs, of which 183,035 PSUs were exchanged for common shares issued from treasury and 191,938 PSUs were settled at their cash value as payment for tax withholdings related to the settlement of the PSUs. Additionally, during 2017, a total of 60,961 PSUs were forfeited.

As at December 31, 2017, a total of 955,028 PSUs are granted and outstanding under the PSU plan.

Directors Deferred Share Units

APUC has a Directors' Deferred Share Unit Plan.  Under the plan, non-employee directors of APUC receive 50% of their annual compensation in deferred share units (“DSUs”) and may elect to receive any portion of their remaining compensation in DSUs.  The DSUs provide for settlement in cash or shares at the election of APUC.  As APUC does not expect to settle the DSUs in cash, these DSUs are accounted for as equity awards. During the twelve months ended December 31, 2017, the Company issued 69,243 DSUs (including DSUs in lieu of dividends) to the directors of the Company.

As at December 31, 2017, a total of 293,906 DSUs had been granted under the DSU plan.

Employee Share Purchase Plan

APUC has an Employee Share Purchase Plan (the “ESPP”) which allows eligible employees to use a portion of their earnings to purchase common shares of APUC. The aggregate number of shares reserved for issuance from treasury by APUC under this plan shall not exceed 2,000,000 shares. During the twelve months ended December 31, 2017, the Company issued 283,523 common shares to employees under the ESPP.

As at December 31, 2017, a total of 779,553 shares had been issued under the ESPP.

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

MANAGEMENT OF CAPITAL STRUCTURE

APUC views its capital structure in terms of its debt and equity levels at its individual operating groups and at an overall company level.

APUC’s objectives when managing capital are:

• To maintain its capital structure consistent with investment grade credit metrics appropriate to the sectors in which APUC operates;

• To maintain appropriate debt and equity levels in conjunction with standard industry practices and to limit financial constraints on the use of capital;

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

• To ensure generation of cash is sufficient to fund sustainable dividends to shareholders as well as meet current tax and internal capital requirements;

• To maintain sufficient cash reserves on hand to ensure sustainable dividends made to shareholders; and

• To have appropriately sized revolving credit facilities available for ongoing investment in growth and development opportunities.

APUC monitors its cash position on a regular basis to ensure funds are available to meet current normal as well as capital and other expenditures. In addition, APUC continuously reviews its capital structure to ensure its individual business groups are using a capital structure which is appropriate for their respective industries.

RELATED PARTY TRANSACTIONS

Emera Inc.

An executive at Emera Inc. ("Emera") was a member of the Board of APUC until June 8, 2017. The Energy Services Business sold electricity to Maine Public Service Company, and Bangor Hydro, both of which are subsidiaries of Emera. The portion considered related party transactions during 2017 amounts to U.S. $4.4 million as compared to U.S. $10.2 million during the same period in 2016. The Liberty Utilities Group purchased natural gas from Emera for its gas utility customers. The portion considered related party transactions during 2017 amounts to U.S. $1.0 million as compared to U.S. $3.9 million during the same period in 2016. Both the sale of electricity to Emera and the purchase of natural gas from Emera followed a public tender process, the results of which were approved by the regulator in the relevant jurisdiction.

In 2016, a subsidiary of the Company and Emera Utility Services Inc. entered into a design, engineering, supply, and construction agreement for the Tinker transmission upgrade project. The transmission upgrade was placed in service in the second quarter of 2017, with the final completion of the contract work in the fourth quarter of 2017. The total cost of the contract was $9.5 million. The contract followed a market based request for proposal process. On October 14, 2016, APUC paid $0.7 million to Emera as reimbursement for professional services incurred and accrued in 2014.

There was U.S. $1.5 million included in accruals in 2017 as compared to U.S. $0.8 million during the same period in 2016 related to these transactions.

Equity-method investments

The Company provides administrative services to its equity-method investees and is reimbursed for incurred costs. To that effect, the Company charged its equity-method investees $6.0 million in 2017 as compared to $3.3 million during the same period in 2016.

Trafalgar

In 2016, the Company received U.S. $10.1 million in proceeds from the settlement of the Trafalgar matter and paid U.S. $2.9 million to an entity partially and indirectly owned by Senior Executives as its proportionate share. The gain to APUC, net of legal and other liabilities, of approximately U.S. $6.6 million was recorded in 2016.

Long Sault Hydro Facility

Effective December 31, 2013, APUC acquired the shares of Algonquin Power Corporation Inc. (“APC”) which was partially owned by Senior Executives.  APC owns the partnership interest in the 18 MW Long Sault Hydro Facility.  A final post-closing adjustment related to the transaction remains outstanding.

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

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

ENTERPRISE RISK MANAGEMENT

The Corporation is subject to a number of risks and uncertainties. A risk is the possibility that an event might happen in the future that could have a negative effect on the financial condition, financial performance or business of the Corporation. The actual effect of any event on the Corporation’s business could be materially different from what is anticipated. The description of risks below does not include all possible risks.

An enterprise risk management, or "ERM", framework is embedded across the organization that systematically and broadly identifies, assesses, and mitigates the key strategic, operational, financial, and compliance risks that may impact the achievement of the Corporation’s current objectives, as well as those inherent to strategic alternatives available to the Corporation. The Corporation’s ERM policy details the risk management processes, risk appetite, and risk governance structure which clearly establishes accountabilities for managing risk across the organization.

As part of the risk management processes, risk registers have been developed across the organization through ongoing risk identification and risk assessment exercises facilitated by the Corporation’s internal ERM team. Risk information is sourced throughout the organization using a variety of methods including risk identification interviews and workshops, as well as the Corporation's “Risk Insights” program, which provides all employees with a mechanism to communicate risks and opportunities at any time. Key risks and associated mitigation strategies are reviewed by the executive-level Enterprise Risk Management Council and are presented to the Board’s Risk Committee on a quarterly basis.

Risks are evaluated consistently across the organization using a common risk scoring matrix to assess impact and likelihood. Financial, reputational, and safety implications are among those considered when determining the impact of a potential risk. Risk treatment priorities are established based upon these risk assessments and incorporated into the development of the Corporation’s strategic and business plans.

The development and execution of risk treatment plans for the organization’s top risks are actively monitored by the Company's senior leadership team and Board of Directors. The Corporation’s internal audit team is responsible for conducting audits to validate and test the effectiveness of controls for key risks. Audit findings are discussed with business owners and reported to the Audit Committee of the Board of Directors on a quarterly basis. All material changes to exposures, controls or treatment plans of key risks are reported to the ERM team, Enterprise Risk Management Council, the Corporate Governance and Risk Committees, and the Board of Directors of the Corporation for consideration.

The Corporation’s ERM framework follows the guidance of ISO 31000:2009. The Board oversees management to ensure the risk governance structure and risk management processes are robust, and that the Corporation’s risk appetite is thoroughly considered in decision-making across the organization

The risks discussed below are not intended as a complete list of all exposures that APUC is encountering or may encounter. A further assessment of APUC and its subsidiaries’ business risks is set out in the Company's most recent AIF available on SEDAR.

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

Treasury Risk Management

Downgrade in the Company's Credit Rating Risk

APUC has a long term consolidated corporate credit rating of BBB (flat) from S&P and a BBB (low) rating from DBRS. Algonquin Power Co ("APCo"), the parent company for the Liberty Power Group, has a BBB (flat) issuer rating from S&P and BBB (low) issuer rating from DBRS. Liberty Utilities Finance GP1 ("Liberty Finance"), a special purpose financing entity of Liberty Utilities Co., the parent company for the Liberty Utilities Group, has a BBB (high) issuer rating from DBRS. Empire has a BBB rating from S&P and a Baa1 rating from Moody's.

The ratings indicate the agencies’ assessment of APUC's ability to pay the interest and principal of debt securities it issues. 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 APUC’s or its subsidiaries' issuer corporate credit ratings would result in an increase in APUC’s borrowing costs under its bank credit facilities and future long-term debt securities issued. If any of APUC’s ratings fall below investment grade (investment grade is defined as BBB- or above for S&P and BBB low or above for DBRS), APUC’s ability to issue short-term debt or other securities or to market those securities would be impaired or made more difficult or expensive. Therefore, any such downgrades could have a material adverse effect on APUC’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 APUC’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.

No assurances can be provided that any of APUC's current ratings will remain in effect for any given period of time or that a rating will not be lowered or withdrawn entirely by a rating agency if, in its judgment, circumstances in the future so warrant.

Capital Markets and Liquidity Risk

As of December 31, 2017, the Company had approximately $3,864.5 million of long-term consolidated indebtedness. Management of the Company believes, based on its current expectations as to the Company’s future performance, that the cash flow from its operations and funds available to it under its revolving 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, expected revenue and the costs of planned capital expenditures are only estimates. Moreover, actual cash flows from operations are dependent on regulatory, market and other conditions that are beyond the control of the Company. As such, no assurance can be given that management’s expectations as to future performance will be realized.

The ability of the Company to raise additional debt or equity or to do so on favorable terms may be affected by the Company’s financial and operational performance, and by financial market disruptions or other factors outside the control of the Company.

In addition, the Company may at times incur indebtedness in excess of its long-term leverage targets, in advance of raising the additional equity necessary to repay such indebtedness and maintain its long-term leverage target. Any increase in the degree of the Company’s leverage could, among other things, limit the Company’s ability to obtain additional financing for working capital, investment in subsidiaries, capital expenditures, debt service requirements, acquisitions and general corporate or other purposes; restrict the Company’s flexibility and discretion to operate its business; limit the Company’s ability to declare dividends on its common shares; require the Company to dedicate a portion of cash flows from operations to the payment of interest on its existing indebtedness, in which case such cash flows will not be available for other purposes; cause ratings agencies to re-evaluate or downgrade the Company’s existing credit ratings; 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 that have less debt; make the Company vulnerable to any downturn in general economic conditions; and render the Company unable to make expenditures that are important to its future growth 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 that any indebtedness of the Company will be refinanced or that additional financing on commercially reasonable terms will be obtained, if at all. In the event that such indebtedness cannot be refinanced, or if it can be refinanced on terms that are less favorable than the current terms, the ability of the Company to declare dividends may be adversely affected.

The ability of the Company to meet its debt service requirements will depend on its ability to generate cash in the future, which depends on many factors, including the financial performance of the Company, debt service obligations, the realization of the anticipated benefits of acquisition and investment activities, and working capital and future capital expenditure requirements. In addition, the ability of the Company 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

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

of the relevant indebtedness. If such indebtedness were to be accelerated, there can be no assurance that the assets of the Company would be sufficient to repay such indebtedness in full. There can also be no assurance that the Company will generate cash flows in amounts sufficient to pay outstanding indebtedness or to fund any other liquidity needs.

Interest Rate Risk

The majority of debt outstanding in APUC and its subsidiaries is subject to a fixed rate of interest and as such is not subject to significant interest rate risk in the short to medium term time horizon.

Borrowings subject to variable interest rates can vary significantly from month to month, quarter to quarter and year to year. APUC does not actively manage interest rate risk on its variable interest rate borrowings due to the primarily short term and revolving nature of the amounts drawn.

Based on amounts outstanding as at December 31, 2017, the impact to interest expense 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, 2017. As a result, a 100 basis point change in the variable rate charged would not impact interest expense;

• The Liberty Power Group's revolving credit facility is subject to a variable interest rate and had $44.8 million outstanding as at December 31, 2017. A 100 basis point change in the variable rate charged would impact interest expense by $0.4 million annually;

• The Liberty Utilities Group's revolving credit facilities are subject to a variable interest rate and had $16.3 million outstanding as at December 31, 2017. As a result, a 100 basis point change in the variable rate charged would impact interest expense by $0.2 million annually.

• The Liberty Utilities Group's commercial paper program is subject to a variable interest rate and had $7.0 million (U.S. $5.6 million) outstanding at December 31, 2017. As a result, a 100 basis point change in the variable rate charged would impact interest expense by $0.1 million annually.

• The Corporate Term Facility is subject to a variable interest rate and had $169.4 million (U.S. $135.0 million) outstanding as at December 31, 2017. A 100 basis point change in the variable rate charged would impact interest expense by $1.7 million annually;

To mitigate financing risk, from time to time APUC may seek to fix interest rates on expected future financings. In the fourth quarter of 2014, the Liberty Power Group entered into a hedge to fix the underlying interest rate for the anticipated refinancing of its $135.0 million bond maturing in July 2018. Hedge accounting treatment applies to this transaction. Consequently, changes in fair value, to the extent deemed effective, are being recorded in Other Comprehensive Income.

Foreign Currency Risk

Currency fluctuations may affect the Canadian dollar equivalent cash flows that APUC realizes from its consolidated operations because a significant portion of the Company's revenues are generated through APUC subsidiary businesses which sell electricity or provide utility services in the United States and receive proceeds from such sales in U.S. dollars. Such APUC businesses also incur costs in U.S. dollars. At the current exchange rate, approximately 93% of Adjusted EBITDA in 2017 and 93% of cash flow from operations is generated in U.S. dollars.

APUC estimates that, on an unhedged basis, a $0.10 increase in the strength of the U.S. dollar relative to the Canadian dollar would result in a net impact on U.S. operations of approximately $82.3 million ($0.22 per share) on an annual basis. In light of the currency profile of its operations, APUC pays its dividend in U.S. dollars. APUC further manages currency risk through the matching of U.S. dollar denominated long term debt for the debt requirements of its U.S. operations, thereby creating a natural hedge for the operating profit vis a vis financing costs.

APUC 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. To the extent that the Company does enter into currency hedges, the Company may not realize the full benefits of favorable 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.

Effective the first quarter of 2018, APUC will begin to report its results in U.S. dollars.

Tax Risk and Uncertainty

The Company is subject to income and other taxes primarily in the United States and Canada. Changes in tax laws or interpretations thereof in the jurisdictions in which APUC does business could adversely affect the Company’s results from operations, our return to shareholders, and cash flow.

The Company cannot provide assurance that the Canada Revenue Agency, the Internal Revenue Service or any other applicable taxation authority will agree with the tax positions taken by the Company, including with respect to claimed expenses and the

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

cost amount of the Company’s depreciable properties.  A successful challenge by an applicable taxation authority regarding such tax positions could adversely affect our results of operations and financial position.

Development by the Liberty Power Group of renewable power generation facilities in the United States depends in part on federal tax credits and other tax incentives. Although these incentives have been extended on multiple occasions, the most recent extension provides for a multi-year step-down.  While recently enacted U.S. tax reform legislation did not make any changes to the multi-year step-down, there can be no assurance that there will not be further changes in the future.  If these incentives are reduced or APUC is unable to complete construction on anticipated schedules, the reduced incentives may be insufficient to support continued development and construction of renewable power facilities in the United States or may result in substantially reduced benefits from facilities that APUC is committed to complete. In addition, the Liberty Power Group has entered into certain tax equity financing transactions with financial partners for certain of its renewable power facilities in the United States, under which allocations of future cash flows to the Company from the applicable facility could be adversely affected in the event that there are changes in U.S. tax laws that apply to facilities previously placed in service.

On December 22, 2017, H.R. 1, the Tax Cuts and Jobs Act was signed into law which resulted in significant changes to U.S. tax law that will affect the Company (See U.S. Tax Reform).

Credit/Counterparty Risk

APUC and its subsidiaries, through its long term power purchase contracts, trade receivables, derivative financial instruments and short term investments, are subject to credit risk with respect to the ability of customers and other counterparties to perform their obligations to the Company.

Liberty Power Group's revenues are approximately 15% of total Company revenues. Approximately 94% of the Liberty Power Group's revenues are earned from large utility customers having a credit rating of Baa2 or better by Moody's, or BBB or higher by S&P, or BBB or higher by DBRS. The following chart sets out the Liberty Power Group’s customers representing greater than 5% of total Liberty Power Group revenues and their credit ratings:

Counterparty	Credit Rating 1	Approximate Annual Revenues		Percentage of Liberty Power Group Revenue
PJM Interconnection LLC	Aa2	$	31.8	11.2	%
Manitoba Hydro	Aa2	30.3		10.7	%
Hydro Quebec	Aa2	29.1		10.3	%
Commonwealth Edison	A3	26.4		9.3	%
Xcel Energy	A3	24.2		8.6	%
Pacific Gas and Electric Company	A3	24.1		8.5	%
Wolverine Power Supply	A	23.5		8.3	%
Ontario Electricity Financial Corporation	Aa2	22.9		8.1	%
Electric Reliability Council of Texas (ERCOT)	Aa3	16.7		5.9	%
Connecticut Light and Power	Baa1	16.2		5.7	%
Total		$	245.2

1 Ratings by DBRS, Moody’s, or S&P.

The remaining revenue of the Company is primarily earned by the Liberty Utilities Group. In this regard, the credit risk attributed to the Liberty Utilities Group's accounts receivable balances at the water and wastewater distribution systems total U.S. $10.4 million which is spread over approximately 160,000 connections, resulting in an average outstanding balance of approximately U.S. $70 dollars per connection.

The natural gas distribution systems accounts receivable balances related to the natural gas utilities total U.S. $21.1 million, while electric distribution systems accounts receivable balances related to the electric utilities total U.S. $99.9 million. The natural gas and electrical utilities both derive over 84% of their revenue from residential customers.

Adverse conditions in the energy industry 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 fully compensated through bad debt reserves approved by the applicable utility regulator. If a customer under a long-term power purchase agreement with the Liberty Power Group is unable to perform, the Liberty Power Group may be unable to replace the contract on comparable terms, in which case sales of power (and, if applicable, renewable energy credits and ancillary services) from the facility would be subject to market price risk and may require refinancing of indebtedness related to the facility or otherwise have a material adverse effect. Default by other

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

counterparties, including counterparties to hedging contracts that are in an asset position and to short-term investments, also could adversely affect the financial results of the Corporation.

Market Price Risk

The Liberty Power Group predominantly enters into long term PPAs for its generation assets and hence is not exposed to market risk for this portion of its portfolio. Where a generating asset is not covered by a power purchase contract, the Liberty Power Group may seek to mitigate market risk exposure by entering into financial or physical power hedges requiring that a specified amount of power be delivered at a specified time in return for a fixed price. There is a risk that the Company is not able to generate the specified amount of power at the specified time resulting in production shortfalls under the hedge that then requires the Company to purchase power in the merchant market. To mitigate the risk of production shortfalls under hedges, the Liberty Power Group generally seeks to structure hedges to cover less than 100% of the anticipated production, thereby reducing the risk of not producing the minimum hedge quantities. Nevertheless, due to unpredictability in the natural resource or due to grid curtailments or mechanical failures, production shortfalls may be such that the Liberty Power Group may still be forced to purchase power in the merchant market at prevailing rates to settle against a hedge.

Hedges currently put in place by the Liberty Power Group along with residual exposures to the market are detailed below:

The July 1, 2012 acquisition of the Sandy Ridge Wind Facility included a financial hedge, which commenced on January 1, 2013, for a 10 year period.  The financial hedge is structured to hedge 72% of the Sandy Ridge Wind Facility’s expected production volume against exposure to PJM Western Hub current spot market rates. The annual unhedged production based on long term projected averages is approximately 44,000 MW-hrs annually. Therefore, each U.S. $10 per MW-hr change in the market price would result in a change in revenue of approximately U.S. $0.4 million for the year.

A second hedge for the Sandy Ridge Wind Facility will commence on January 1, 2023, for a one year period. The financial hedge is structured to hedge 73% of the Sandy Ridge Wind Facility’s expected production volume against exposure to PJM Western Hub current spot market rates. The annual unhedged production based on long term projected averages is approximately 42,000 MW-hrs annually.

The December 10, 2012 acquisition of the Senate Wind Facility included a physical hedge, which commenced on January 1, 2013, for a 15 year period. The physical hedge is structured to hedge 64% of the Senate Wind Facility’s expected production volume against exposure to ERCOT North Zone current spot market rates.  The annual unhedged production based on long term projected averages is approximately 188,000 MW-hrs annually. Therefore, each U.S. $10 per MW-hr change in the market price would result in a change in revenue of approximately U.S. $2.0 million for the year.

The December 10, 2012 acquisition of the Minonk Wind Facility included a financial hedge, which commenced on January 1, 2013, for a 10 year period. The financial hedge is structured to hedge 73% of the Minonk Wind Facility’s expected production volume against exposure to PJM Northern Illinois Hub current spot market rates. The annual unhedged production based on long term projected averages is approximately 186,000 MW-hrs annually. Therefore, each U.S. $10 per MW-hr change in market prices would result in a change in revenue of approximately U.S. $2.0 million for the year.

A second hedge for the Minonk Wind Facility will commence on January 1, 2023, for a one year period. The financial hedge is structured to hedge 72% of the Minonk Wind Facility’s expected production volume against exposure to PJM Northern Illinois Hub current spot market rates. The annual unhedged production based on long term projected averages is approximately 189,000 MW-hrs annually.

Under each of the above noted hedges, if production is not sufficient to meet the unit quantities under the hedge, the shortfall must be purchased in the open market at market rates. The effect of this risk exposure could be material but cannot be quantified as it is dependent on both the amount of shortfall and the market price of electricity at the time of the shortfall.

In addition to the above noted hedges, from time to time the Liberty Power Group enters into short-term derivative contracts (with terms of one to three months) to further mitigate market price risk exposure due to production variability. As at December 31, 2017, the Liberty Power Group had entered into hedges with a cumulative notional quantity of 7,080 MW-hrs.

The January 1, 2013 acquisition of the Shady Oaks Wind Facility included a power sales contract, which commenced on June 1, 2012 for a 20 year period. The power sales contract is structured to hedge the preponderance of the Shady Oaks Wind Facility’s production volume against exposure to PJM ComEd Hub current spot market rates.  For the unhedged portion of production based on expected long term average production, each U.S. $10 per MW-hr change in market prices would result in a change in revenue of approximately U.S. $0.5 million for the year.

Commodity Price Risk

The Liberty Power Group’s exposure to commodity prices is primarily limited to exposure to natural gas price risk. The Liberty Utilities Group is exposed to energy and natural gas price risks at its electric and natural gas systems. In this regard, a discussion of this risk is set out as follows:

Algonquin Power & Utilities Corp. - Management Discussion & Analysis 48

• The Sanger Thermal Facility’s PPA includes provisions which reduce its exposure to natural gas price risk. In this regard, a $1.00 increase in the price of natural gas per MMBTU, based on expected production levels, would result in a decrease in net revenue by approximately $0.2 million on an annual basis.

• The Windsor Locks Thermal Facility’s Energy Services Agreement includes provisions which reduce its exposure to natural gas price risk but has exposure to market rate conditions for sales above those to its primary customer. In this regard, a $1.00 increase in the price of natural gas per MMBTU, based on expected production levels, would result in a decrease in net revenue by approximately $0.1 million on an annual basis.

• The Maritime region provides short-term energy requirements to various customers at fixed rates. The energy requirements of these customers are estimated at approximately 181,000 MW-hrs in fiscal 2018, of which 170,000 MW-hrs is presently contracted. While the Tinker Hydro Facility is expected to provide the majority of the energy required to service these customers, the Maritime region anticipates having to purchase approximately 37,000 MW-hrs of its energy requirements at the ISO-NE spot rates to supplement self-generated energy should the Maritime region be able to reach the estimated 181,000 MW-hrs. The risk associated with the expected market purchases of 37,000 MW-hrs is mitigated through the use of short-term financial energy hedge contracts which cover approximately 20% of the Maritime region's anticipated purchases during the price-volatile winter months at an average rate of approximately $86 per MW-hr. For the amount of anticipated purchases not covered by hedge contracts, each U.S. $10.00 change per MW-hr in the market prices in ISO-NE would result in a change in expense of $0.3 million on an annualized basis.

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 ECAC mechanism, which allows for the recovery or refund of changes in energy costs that are caused by the fluctuations in the price of fuel and purchased power. On a monthly basis, energy costs are compared to the CPUC approved base tariff energy rates and the difference is deferred to a balancing account. Annually, based on the balance of the ECAC balancing account, if the ECAC revenues were to increase or decrease by more than 5%, the Calpeco Electric System's ECAC tariff allows for a potential adjustment to the ECAC rates which would eliminate the risk associated with the fluctuating cost of fuel and purchased power.

The Granite State Electric System is an open access electric utility allowing for its customers to procure commodity services from competitive energy suppliers. For those customers that do not choose their own competitive energy supplier, Granite State Electric System provides a Default Service offering to each class of customers through a competitive bidding process. This process is undertaken semi-annually for all customers. The winning bidder is obligated to provide a full requirements service based on the actual needs of the Granite State Electric System’s Default Service customers. Since this is a full requirements service, the winning bidder(s) take on the risk associated with fluctuating customer usage and commodity prices. The supplier is paid for the commodity by the Granite State Electric System which in turns receives pass-through rate recovery through a formal filing and approval process with the NHPUC on a semi-annual basis. The Granite State Electric System is only committed to the winning Default Service supplier(s) after approval by the NHPUC so that there is no risk of commodity commitment without pass-through rate recovery.

The EnergyNorth Natural Gas System 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 approved by the NHPUC bi-annually through Least Cost Integrated Resource Plan filing. In addition, EnergyNorth Natural Gas System files with the NHPUC for recovery of its transportation and commodity costs on a semi-annual basis through the Cost of Gas ("COG") filing and approval process. The EnergyNorth Natural Gas System establishes rates for its customers based on the NHPUC approval of its filed COG. These rates are designed to fully recover its anticipated transportation and commodity costs. In order to minimize commodity price fluctuations, the EnergyNorth Natural Gas System locks in a fixed price basis for approximately 14% of its normal winter period purchases under a NHPUC approved hedging program. All costs associated with the fixed basis hedging program are allowed to be a pass-through to customers through the COG filing and the approved rates in said filing. Should commodity prices increase or decrease relative to the initial semi-annual COG rate filing, the EnergyNorth Natural Gas System has the right to automatically adjust its rates going forward in order to minimize any under or over collection of its gas costs. In addition, any under collections may be carried forward with interest to the next year’s corresponding COG filing, i.e. winter to winter and summer to summer.

The Midstates Gas Systems purchases pipeline capacity, storage and commodity from a variety of counterparties, and files with the three individual state commissions for recovery of its transportation and commodity costs through an annual Purchase Gas Adjustment (“PGA”) filing and approval process. The Midstates Gas Systems establishes rates for its customers within the PGA filing and these rates are designed to fully recover its anticipated transportation and commodity costs. In order to minimize commodity price fluctuations, the Company has implemented a commodity hedging program designed to hedge approximately 25-50% of its non-storage related commodity purchases. All gains and losses associated with the hedging

Algonquin Power & Utilities Corp. - Management Discussion & Analysis 49

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 gas costs.

The Georgia (Peach State) Gas System purchases pipeline capacity, storage and commodity from a variety of counterparties, and files with the Georgia 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 gas costs relative to the amounts assumed in the PGA filings, minimizing any under or over collection of its gas costs.

Empire has a fuel cost recovery mechanism in all of its jurisdictions, as such impacts on net income exposure to commodity cost fluctuations are significantly reduced. However, cash flow could still be impacted by any increased expenditures. Empire met approximately 58% of its 2017 generation fuel supply need through coal. Approximately 97% of its 2017 coal supply was Western coal. Empire has contracts and binding proposals to supply a portion of the fuel for its coal plants through 2018. These contracts and inventory on hand satisfy approximately 56% of anticipated fuel requirements for 2018 for the Asbury Coal Facility.

Empire is exposed to changes in market prices for natural gas needed to run combustion turbine generators. Empire's natural gas procurement program is designed to manage costs to avoid volatile natural gas prices. Empire periodically enters into physical forward and financial derivative contracts with counterparties to meet future natural gas requirements by locking in prices (with respect to predetermined percentages of our expected future natural gas needs) in an attempt to lessen the volatility in fuel expenditures and improve predictability. Gains and losses associated with the hedging program are passed through to customers in the fuel adjustment clause and PGA filings and are embedded in the approved rates in such filings.

OPERATIONAL RISK MANAGEMENT

Mechanical and Operational Risks

APUC's profitability could be impacted by, among other things, equipment failure, the failure of a major customer to fulfill its contractual obligations under its PPA, reductions in average energy prices, a strike or lock-out at a facility, natural disasters, interruption in supply chain and expenses related to claims or clean-up to adhere to environmental and safety standards.

The Liberty Power Group's hydro assets utilize dams to pond water for generation and if the dams fail/breach potentially catastrophic amounts of water would flood downriver from the facility. The dams can be subjected to drought conditions and lose the ability to generate during peak load conditions, causing the facilities to fall short of either hedged or PPA committed production levels. The risks of the hydro facilities are mitigated by regular dam inspections and a maintenance program of the facility to lessen the risk of dam failure.

The Liberty Power Group's wind assets could catch on fire and, depending on the season, could ignite significant amounts of forest or crop downwind from the wind farms. The wind units could also be affected by large atmospheric conditions, which will lower wind levels below our PPA and hedge minimum production levels. The wind units can experience failures in the turbine blades or in the supporting towers. Production risks associated with the wind turbine generators failures is mitigated by properly maintaining the units, using long term maintenance agreements with the turbine O&Ms which provide for regular inspections and maintenance of property, and liability insurance policies. Icing can be mitigated by shutting down the unit as icing is detected at the site.

The Liberty Power Group's Thermal Energy Division uses natural gas and oil, and produces exhaust gases, which if not properly treated and monitored could cause hazardous chemicals to be released into the atmosphere.  The units could also be restricted from purchasing gas/oil due to either shortages or pollution levels, which could hamper output of the facility. The mechanical and operational risks at the thermal facilities are mitigated through the regular maintenance of the boiler system, and by continual monitoring of exhaust gases. Fuel restrictions can be hedged in part by long term purchases.

All of the Liberty Power Group's electric generating stations are subject to mechanical breakdown. The risk of mechanical breakdown is mitigated by properly maintaining the units and by regular inspections.

The Liberty Utilities Group's water and wastewater distribution systems operate under pressurized conditions within pressure ranges approved by regulators.  Should a water distribution network become compromised or damaged, the resulting release of pressure could result in serious injury or death to individuals or damage to other property.

The Liberty Utilities Group's electric distribution systems are subject to storm events, usually winter storm events, whereby power lines can be brought down, with the attendant risk to individuals and property. In addition, in forested areas, power lines brought down by wind can ignite forest fires which also bring attendant risk to individuals and property.

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The Liberty Utilities Group's natural gas distribution systems are subject to risks which may lead to fire and/or explosion which may impact life and property. Risks include third party damage, compromised system integrity, type/age of pipelines, and severe weather events.

These risks are mitigated through the diversification of APUC’s operations, both operationally and geographically, the use of regular maintenance programs, including pipeline safety programs and compliance programs, and maintaining adequate insurance, an active Enterprise Risk Management program and the establishment of reserves for expenses.

Regulatory Risk

Profitability of APUC businesses is, in part, dependent on regulatory climates in the jurisdictions in which those businesses operate. In the case of some Liberty Power Group hydroelectric facilities, water rights are generally owned by governments that reserve the right to control water levels, which may affect revenue.

The Liberty Utilities Group’s facilities are subject to rate setting by state regulatory agencies. The Liberty Utilities Group operates in 12 different states and therefore is subject to regulation from 12 different regulatory agencies. The time between the incurrence of costs and the granting of the rates to recover those costs by state regulatory agencies is known as regulatory lag. As a result of regulatory lag, inflationary effects may impact the ability to recover expenses, and profitability could be impacted. In order to mitigate this exposure, the Liberty Utilities Group seeks to obtain approval for regulatory constructs in the states in which it operates to allow for timely recovery of operating expenses. A fundamental risk faced by any regulated utility is the disallowance of costs to be placed into its revenue requirement by the utility's regulator. To the extent proposed costs are not allowed into rates, the utility will be required to find other efficiencies or cost savings to achieve its allowed returns.

The Liberty Utilities Group regularly works with its governing authorities to manage the affairs of the business, employing both local, state level, and corporate resources.

On December 22, 2017, the Tax Cuts and Jobs Act was signed into law which resulted in significant changes to U.S. tax law. Amongst other things, the Act reduced the federal corporate income tax rates from 35% to 21%. The change in corporate tax rates will have a significant impact on the financial operations and regulatory revenue requirements of most public utilities, including the Liberty Utilities Group. The Liberty Utilities Group is working with stakeholders to understand the full implications and impact of the new law. Liberty believes that customers will be best served by dealing with Tax Reform within the context of a full regulatory rate case, where all factors that comprise rates can be considered.

Condemnation Expropriation Proceedings

The Liberty Utilities Group's distribution systems could be subject to condemnation or other methods of taking by government entities under certain conditions. Any taking by government entities would legally require fair compensation to be paid. Determination of such fair compensation is undertaken pursuant to a legal proceeding and, therefore, there is no assurance that the value received for assets taken will be in excess of book value.

Mountain Water Condemnation Proceedings

On May 6, 2014, the City of Missoula, Montana filed a lawsuit against Mountain Water Company and its prior indirect owner Carlyle Infrastructure Partners, L.P. (“Carlyle”), seeking to condemn the assets of Mountain Water. The case went to trial on the right to take or “necessity” phase in March, 2015. The District Court issued a Preliminary Order of Condemnation on June 15, 2015, finding that the City had established the right to take the assets of Mountain Water. Mountain Water filed an appeal with the Montana Supreme Court. The case then proceeded to a trial on valuation before three Commissioners. On November 17, 2015, the Commissioners issued a report finding that the “fair market value” of the condemned property as of May 6, 2014 was U.S. $88.6 million. On August 2, 2016, the Supreme Court of Montana upheld the District Court’s decision, permitting the City of Missoula to proceed with the condemnation of Mountain Water’s assets.

On December 22, 2015, certain developers filed a lawsuit in Montana District Court against the City of Missoula and Mountain Water seeking resolution of claims to a portion of the condemnation award on the basis that certain of the assets being condemned had been funded by such parties. On February 21, 2017, the court in that case recognized an equitable lien on such assets in favor of the developers and ordered that a portion of the condemnation award, if and when paid, be paid by the City of Missoula to the court for direct payment to the developers.

On or about June 5, 2017, Mountain Water, Liberty Utilities Co. and the City of Missoula entered into a Settlement Agreement and Release of Claims, resolving certain issues in the event that the City acquired possession of Mountain Water’s assets, and contingent upon settlement of the developer lawsuit. The settlement agreement was approved by the condemnation court in hearings on June 15 and June 22, 2017, and a final order of condemnation was issued on June 22, 2017. The developer lawsuit was dismissed on June 30, 2017. On June 22, 2017, the City of Missoula paid the condemnation judgment, including amounts owed to Mountain Water and amounts required to be paid to the developers. The City of Missoula took possession of Mountain Water’s assets on that date. Carlyle and Mountain Water have appealed certain elements of the final order of condemnation including, among other issues, recovery of post-summons interest and attorney’s fees.

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Apple Valley Condemnation Proceedings

On January 7, 2016, the Town of Apple Valley filed a lawsuit seeking to condemn the utility assets of Liberty Utilities (Apple Valley Ranchos Water) Corp.   The Town seeks to condemn the utility assets of Apple Valley and to require a determination of fair market value.  In the first phase of the case, the Court will determine the necessity of the taking by the Town.  If the Court determines that necessity has been established, in a second phase, a jury will determine the fair market value of the assets being condemned.  The condemnation case is currently proceeding in discovery.  Resolution of the condemnation proceedings is expected to take two to three years.  The Court has been briefed on a related California Environmental Quality Act ("CEQA") lawsuit (challenging the Town’s compliance with CEQA in connection with the proposed condemnation) and heard oral argument in December 2017.   The Court issued the CEQA decision on February 9, 2018 and denied Liberty Apple Valley’s CEQA claim.   As a result, the condemnation case will proceed. The Court has set a scheduling conference for the condemnation case on March 6, 2018 to potentially set a trial date on the first phase of the condemnation action.

Acquisition Risk

Part of the Company's business strategy is to acquire new generating stations and existing regulated utilities. The Company's acquisition strategy introduces exposures inherent to such transactions that may adversely affect the results of an acquisition, including delays in implementation or unexpected costs or liabilities, as well as the risk of failing to realize operating benefits or synergies. The Company mitigates these risks by following systematic procedures for integrating acquisitions, applying strict financial metrics to any potential acquisition and subjecting the process to close monitoring and review by the Board of Directors.

When acquisitions occur, significant demands can be placed on the Company’s managerial, operational and financial personnel and systems. No assurance can be given that the Company’s systems, procedures and controls will be adequate to support the expansion of the Company’s operations resulting from the acquisition. The Company’s future operating results will be affected by the ability of its officers and key employees to manage changing business conditions and to implement and improve its operational and financial controls and reporting systems.

Joint Venture Investment Risk

Certain development and operating entities that the Company has interest in are jointly owned with third parties. The Company may not have the sole discretion or ability to affect the management or operations at such facilities and thereby may not be able to make determinations on how to manage these facilities in light of changing economic circumstances. A divergence in the interests of the Company and the co-owners could negatively impact the realization of the Company's investment in the joint venture business, which may have a disproportionate economic impact relative to the Company's investment.

Asset Retirement Obligations

APUC and its subsidiaries complete periodic reviews of potential asset retirement obligations that may require recognition. As part of this process, APUC 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.

The Liberty Utilities Group’s facilities are operated with the assumption that their services will be required in perpetuity and there are no contractual decommissioning requirements. In order to remain in compliance with the applicable regulatory bodies, the Liberty Utilities Group has regular programs at each facility to ensure its equipment is properly maintained and replaced on a cyclical basis. These costs can generally be included in the facility’s rate base and thus the Liberty Utilities Group expects to be allowed to earn a return on such investment.

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 of wind facilities upon termination of land leases; (ii) cut (disconnect from the distribution system), purge (clean of natural gas and PCB contaminants), and cap gas mains within the gas distribution and transmission system when mains are retired in place, or dispose of sections of 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

Liberty Power Group

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

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

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

The Liberty Power Group's solar generation facilities are impacted by seasonal fluctuations and year to year variability in the solar radiance. For instance, there are more daylight hours in the summer than there are in the winter, resulting in higher production in the summer months. The ability of these facilities to generate income may be impacted by naturally occurring changes in solar radiance.

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

Liberty Utilities Group

The Liberty Utilities Group’s demand for water is affected by weather conditions and temperature. Demand for water during warmer months is generally greater than cooler months due to requirements for irrigation, swimming pools, cooling systems and other outside water use. If there is above normal rainfall or rainfall is more frequent than normal the demand for water may decrease, adversely affecting revenues.

The Liberty Utilities Group’s demand for energy from its electric distribution systems is primarily affected by weather conditions and conservation initiatives. The Liberty Utilities Group provides information and programs to its customers to encourage the conservation of energy. In turn, demand may be reduced which could have short term adverse impacts on revenues.

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

The Company attempts to mitigate the above noted risks by seeking regulatory mechanisms during rate case proceedings. While not all regulatory jurisdictions have approved mechanisms to mitigate demand fluctuations, to date, the Liberty Utilities Group has successfully obtained regulatory approval to implement such decoupling mechanisms in 4 of 12 states representing approximately 25% of customers. 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. The Liberty Utilities Group is presently seeking weather related decoupling mechanism for its utilities in Missouri and New Hampshire.

Development and Construction Risk

The Company actively engages in the development and construction of new power generation facilities. There is always a risk that material delays and/or cost overruns could be incurred in any of the projects planned or currently in construction affecting the company’s overall performance.  There are risks that actual costs may exceed budget estimates, delays may occur in obtaining permits and materials, suppliers and contractors may not perform as required under their contracts, there may be inadequate availability, productivity or increased cost of qualified craft labor, start-up activities may take longer than planned, the scope and timing of projects may change, and other events beyond the Company's control may occur that may materially affect the schedule, budget, cost and performance of projects. Regulatory approvals can be challenged by a number of mechanisms which vary across state and provincial jurisdictions.  Such permitting challenges could identify issues that may result in permits being modified or revoked.

Risks Specific to Renewable Generation Projects:

The strength and consistency of the wind resource will vary from the estimate set out in the initial wind studies that were relied upon to determine the feasibility of the wind facility. If weather patterns change or the historical data proves not to accurately reflect the strength and consistency of the actual wind, the assumptions underlying the financial projections as to the amount of electricity to be generated by the facility may be different and cash could be impacted.

The amount of solar radiance will vary from the estimate set out in the initial solar studies that were relied upon to determine the feasibility of the solar facility. If weather patterns change or the historical data proves not to accurately reflect the strength and consistency of the solar radiance, the assumptions underlying the financial projections as to the amount of electricity to be generated by the facility may be different and cash could be impacted.

For certain of its development projects, the Company relies on financing from third party tax equity Investors. These investors typically provide funding upon commercial operation of the facility. Should certain facilities not meet the conditions required for tax equity funding, expected returns from the facilities may be impacted.

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Litigation Risks and Other Contingencies

APUC and certain of its subsidiaries are involved in various litigations, 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.

See further discussion of claims made by or against APUC or its subsidiaries in Regulatory Risk.

Cybersecurity Risk

The Company's information technology systems may be vulnerable to potential risks from cybersecurity attacks.  Attacks can be caused by malware, viruses, email attachments, acts of war or terrorism and can originate from individuals from both inside and outside the organization.  An attack could result in service disruptions, system failures, the disclosure of personal customer and employee information, and could lead to an adverse effect on the Company's financial performance. A breach of personal or confidential information may also occur as a result of non-cyber means, such as breach of physical security.  Should a material breach occur the Company may not be able to recover all costs and losses through insurance, legal or regulatory processes.

The Company mitigates these risks by maintaining a cybersecurity program that is overseen by the Board of Directors, and executed by a cross functional management team. The program is intended to provide adequate controls for the appropriate protection of critical business systems.  These controls have been put into place to mitigate potential risks, and to improve the organization’s capability to respond and recover from any potential cyber incident.

Energy Consumption and Advancement in Technologies Risk

The Liberty Utilities Group's operations are subject to changes in demand for energy which are impacted by general economic conditions, customer's focus on energy efficiency, and advancements in new technologies.

The Liberty Utilities Group is actively involved in working with governments and customers to ensure these changes in consumption do not negatively impact the services provided. Furthermore, through its strategic initiatives the Liberty Utilities Group is constantly looking for ways to maintain the Company's competitive advantage.

Uninsured Risk

The Company maintains insurance for accidental loss and potential liabilities to third parties. However, there are certain elements of the Liberty Utilities Group's regulated utilities that are not fully insured as the cost of the coverage is not economically viable. In the event that a liability event or loss is not covered through insurance the Liberty Utilities Group would apply to their respective regulator to request recovery through increased customer rates. Cost recovery through this mechanism is subject to regulatory approval and is therefore uncertain.

Insurance coverage for the rest of the Company is also subject to policy conditions and exclusions, coverage limits, and various deductibles, and not all types of liabilities and losses may be covered by insurance, in which case the Company may be financially exposed.

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QUARTERLY FINANCIAL INFORMATION

The following is a summary of unaudited quarterly financial information for the eight quarters ended December 31, 2017:

(all dollar amounts in $ millions except per share information)	1st Quarter 2017		2nd Quarter 2017		3rd Quarter 2017		4th Quarter 2017
Revenue	$	557.9	$	453.2	$	443.3	$	523.4
Net earnings attributable to shareholders	26.0		47.7		59.4		60.0
Net earnings per share	0.07		0.12		0.15		0.14
Adjusted Net Earnings	88.1		53.3		64.9		85.9
Adjusted Net Earnings per share	0.25		0.13		0.16		0.20
Adjusted EBITDA	254.8		197.6		197.5		233.4
Total assets	10,880.7		10,528.6		10,306.7		10,533.6
Long term debt1	4,773.6		4,418.0		4,435.1		3,864.5
Dividend declared per common share	$	0.15	$	0.16	$	0.15	$	0.15
	1st Quarter 2016		2nd Quarter 2016		3rd Quarter 2016		4th Quarter 2016
Revenue	$	341.7	$	222.8	$	221.3	$	310.2
Net earnings attributable to shareholders	42.0		24.8		17.7		46.3
Net earnings per share	0.15		0.08		0.06		0.16
Adjusted Net Earnings	56.1		30.9		26.6		51.4
Adjusted Net Earnings per share	0.21		0.11		0.09		0.18
Adjusted EBITDA	147.9		99.2		91.4		138.3
Total assets	5,615.5		5,555.0		6,020.8		8,249.5
Long term debt1	2,214.5		2,199.9		2,380.8		4,272.0
Dividend declared per common share	$	0.13	$	0.14	$	0.14	$	0.14

1 Includes current portion of long-term debt, long-term debt and convertible debentures.

The quarterly results are impacted by various factors including seasonal fluctuations and acquisitions of facilities as noted in this MD&A.

Quarterly revenues have fluctuated between $221.3 million and $557.9 million over the prior two year period. A number of factors impact quarterly results including acquisitions, seasonal fluctuations, and winter and summer rates built into the PPAs. In addition, a factor impacting revenues year over year is the fluctuation in the strength of the Canadian dollar relative to the U.S. dollar which can result in significant changes in reported revenue from U.S. operations.

Quarterly net earnings attributable to shareholders have fluctuated between $17.7 million and $60 million over the prior two year period. Earnings have been significantly impacted by non-cash factors such as deferred tax recovery and expense, impairment of intangibles, property, plant and equipment and mark-to-market gains and losses on financial instruments.

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DISCLOSURE CONTROLS AND PROCEDURES

APUC's management carried out an evaluation as of December 31, 2017, under the supervision of and with the participation of APUC’s Chief Executive Officer (“CEO”) and Chief Financial Officer (“CFO”), of the effectiveness of the design and operations of APUC’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, 2017, APUC’s disclosure controls and procedures are effective to provide reasonable assurance that information required to be disclosed by APUC in reports that it files or submits under the Exchange Act is recorded, processed, summarized, and reported within the time periods specified in SEC rules and forms, 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 CFO, is responsible for establishing and maintaining adequate internal control over financial reporting (as defined in Rules 13a-15(f) and 15d-15(f) under the Exchange Act) to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with U.S. GAAP.

The Company’s internal control over financial reporting framework includes those policies and procedures that (i) pertain to the maintenance of records that, in reasonable detail, accurately and fairly reflect the transactions and dispositions of the assets of the Company; (ii) provide reasonable assurance that transactions are recorded as necessary to permit preparation of financial statements in accordance with U.S. GAAP, and that receipts and expenditures of the Company are being made only in accordance with authorizations of management and directors of the Company; and (iii) provide reasonable assurance regarding prevention or timely detection of unauthorized acquisition, use or disposition of the Company’s assets that could have a material effect on the Company’s consolidated financial statements.

Due to its inherent limitations, internal control over financial reporting may not prevent or detect all misstatements. 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.

During the year ended December 31, 2017, the Company acquired Empire. Management is in the process of evaluating the existing controls and procedures of Empire and integrating financial reporting and controls for Empire into the Company’s internal control over financial reporting. The financial information for this acquisition is included in this MD&A and in note 3 to the consolidated financial statements. As permitted by National Instrument 52-109 and the SEC, due to the complexity associated with assessing internal controls during integration efforts, the Company excluded this acquisition from its assessment of the effectiveness of the Company's internal controls over financial reporting (representing approximately 30% of our total assets as of December 31, 2017 and approximately 41% of our revenues and 35% of our net income for the year ended December 31, 2017).

Management assessed the effectiveness of the Company's internal control over financial reporting as of December 31, 2017, based on the framework established in Internal Control - Integrated Framework (2013) issued by the Committee of Sponsoring Organizations of the Treadway Commission (COSO). This assessment included review of the documentation of controls, evaluation of the design effectiveness of controls, testing of the operating effectiveness of controls, and a conclusion on this evaluation. Based on this assessment, management concluded that the Company's internal control over financial reporting was effective as of December 31, 2017 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 Committee of the Board of Directors of APUC.

CHANGES IN INTERNAL CONTROLS OVER FINANCIAL REPORTING

For the twelve months ended December 31, 2017, there has been no change in the Company’s internal control over financial reporting that has materially affected, or is reasonably likely to materially affect, the Company’s internal control over financial reporting. The Company continues to implement its internal control structure over the operations of the acquired business discussed above.

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 of fraud. Further, the effectiveness of internal control is subject to the risk that controls may become inadequate because of changes in conditions, or that the degree of compliance with policies or procedures may change.

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CRITICAL ACCOUNTING ESTIMATES AND POLICIES

APUC prepared its consolidated financial statements in accordance with U.S. GAAP.  The preparation of consolidated financial statements requires management to make estimates and assumptions that affect the reported amounts of assets and liabilities, related amounts of revenues and expenses, and disclosure of contingent assets and liabilities.  Significant areas requiring the use of management estimates relate to the useful lives and recoverability of depreciable 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.

APUC’s significant accounting policies and new accounting standards are discussed in notes 1 and 2 to the consolidated financial statements, respectively. Management believes the following accounting policies involve the application of critical accounting estimates. Accordingly, these accounting estimates have been reviewed and discussed with the Audit Committee of the Board of Directors of APUC.

Estimated Useful Lives and Recoverability of Long-Lived Assets, Intangibles and Goodwill

The Company makes judgments a) to determine the recoverability of a development project, and the period over which the costs are capitalized during the development and construction of the project, b) to assess the nature of the costs to be capitalized, c) to distinguish individual components and major overhauls, and d) to determine the useful lives or unit-of-production over which assets are depreciated.

Depreciation rates on 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, including intangible assets and goodwill, is reviewed whenever events or changes in circumstances indicate that such carrying values may not be recoverable, and at least annually for goodwill. Some of the factors APUC considers as indicators of impairment include a significant change in operational or financial performance, unexpected outcome from rate orders, natural disasters, energy pricing and changes in regulation. When such events or circumstances are present, the Company assesses whether the carrying value will be recovered through the expected future cash flows. If the facility includes goodwill, the fair value of the facility is compared to its carrying value. Both methodologies are sensitive to the forecasted cash flows and in particular energy prices, long-term growth rate and, discount rate for the fair value calculation.

A recoverability analysis was performed in 2017 for wind generating assets operating without a PPA and in 2016 for wind and small hydro generating assets without a PPA. No impairment provision was required in 2017 or 2016. A quantitative assessment of goodwill performed as at September 30, 2014 concluded that the fair value of each reporting unit substantially exceeded their carrying value. In 2017 and 2016, Management assessed qualitative and quantitative factors for each of the reporting units that were allocated goodwill. No goodwill impairment provision was required.

Measurement of Deferred Taxes

On December 22, 2017, the U.S. government enacted the Tax Cuts and Jobs Act (the “Act”). The Act made broad and complex changes to the U.S. tax code which impacted 2017 including, but not limited to, reducing the U.S. federal corporate tax rate from 35% to 21% and introducing 100% expensing for certain capital expenditures, excluding regulated utilities, made after September 27, 2017.   Management's judgment is required to measure the deferred taxes assets and liabilities at the enactment date based on these changes.  Where requirements of the implementation of the new Act are incomplete, management uses judgments and assumptions to calculate a reasonable provisional amount to include in the Company's financial statements.

Valuation of Deferred Tax Assets

In assessing the realization of deferred tax assets, management considers whether it is more likely than not that some portion or all of the deferred tax assets will not be realized and provides any necessary valuation allowances as required. Management evaluates the probability of realizing deferred tax assets by reviewing a forecast of future taxable income together with Management's intent and ability to implement tax planning strategies, if necessary, to realize deferred tax assets. Although at this time Management considers it more likely than not that it will have sufficient taxable income to realize the deferred tax assets, there can be no assurance that the company will generate sufficient taxable income in the future to utilize these deferred tax assets. Management also assesses the ability to utilize tax attributes, including those in the form of carryforwards, for which the benefits have already been reflected in the financial statements. Management's assessment has been impacted by the tax reform discussed above.

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

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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 Liberty Utilities Group's operations.

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.

The Financial Accounting Standards Board ("FASB") issued a revenue recognition standard codified as ASC 606, Revenue from Contracts with Customers. The Company expects the adoption of Topic 606 will have an immaterial impact on the consolidated financial statements and the pattern of revenue recognition. The Company intends to adopt the new revenue recognition standard using the modified retrospective method effective January 1, 2018.

Derivatives

APUC 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.  APUC 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 APUC’s results of operations if the hedging relationship was considered no longer effective.

Pension and Post-employment Benefits

The obligations and related costs of defined benefit pension and post-employment benefit plans are calculated using actuarial concepts, which include critical assumptions related to the discount rate, mortality rate, compensation increase, expected rate of return on plan assets and medical cost trend rates. These assumptions are important elements of expense and/or liability measurement and are updated on an annual basis, or upon the occurrence of significant events. The Company used the new mortality improvement scale (MP-2017) recently released by the Society of Actuaries adjusted to reflect the 2017 Social Security Administration ultimate improvement rates.

The FASB issued ASU 2017-07 Compensation—Retirement Benefits (Topic 715): Improving the Presentation of Net Periodic Pension Cost and Net Periodic Post-retirement Benefit Cost, for reporting of defined benefit pension cost and post-retirement benefit cost ("net benefit cost") in the financial statements. The Company will adopt this guidance effective January 1, 2018. Following the effective date of this Accounting Standards Update ("ASU"), the Company expects its regulated operations to only capitalize the service costs component and therefore no regulatory to U.S. GAAP reporting differences are anticipated. The Company intends to apply the practical expedient for retrospective application on the statement of operations.

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Sensitivities

The sensitivities of key assumptions used in measuring accrued benefit obligations and benefit plan cost for 2017 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.

	2017 Pension Plans				2017 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	(65.6	)	(4.4	)	(31.5	)	(1.9	)
1% decrease	81.1		6.7		39.7		2.1
Future compensation rate
1% increase	0.2		1.5		—		—
1% decrease	(0.2	)	(1.3	)	—		—
Expected return on plan assets
1% increase	—		(4.5	)	—		(1.4	)
1% decrease	—		4.5		—		1.4
Life expectancy
10% increase	38.0		3.3		19.7		1.6
10% decrease	(39.9	)	(2.8	)	(18.8	)	(1.8	)
Health care trend
1% increase	—		—		38.0		4.3
1% decrease	—		—		(30.1	)	(3.3	)

Business Combinations

The Company has completed a number of business acquisitions in the past few years. Management's judgment is required to estimate the purchase price, to identify and to fair value all assets and liabilities acquired. The determination of the fair value of assets and liabilities acquired is based upon management’s estimates and certain assumptions generally included in a present value calculation of the related cash flows.

Acquired assets and liabilities assumed that are subject to critical estimates include regulated property, plant and equipment, regulatory assets and liabilities, long-term debt and pension and OPEB obligations. The fair value of regulated property, plant and equipment is assessed using an income approach where the estimated cash flows of the assets are calculated using the approved tariff and discounted at the approved rate of return. The fair value of regulatory assets and liabilities considers the estimated timing of the recovery or refund to customers through the rate making process. The fair value of long-term debt is determined using a discounted cash flow method and current interest rates. The pension and OPEB obligations are valued by external actuaries using the guidelines of ASC 805, Business combinations.

Additional disclosure of APUC’s critical accounting estimates is also available on SEDAR at www.sedar.com and on the APUC website at www.AlgonquinPowerandUtilities.com.

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