EX-99.1 2 ex99_1.htm EXHIBIT 99.1 - ANNUAL REPORT 2019

Exhibit 99.1
Sustaining energy and water for life 2019 Annual report

Algonquin Power & Utilities Corp.AnnualReport2019III Corporate ProfileIV Letter to ShareholdersVI At a GlanceVIII Financial HighlightsXI Regulated Services GroupXI Renewable Energy GroupXII Marching to One MillionXIII A Leader in SustainabilityXIV How We Create Value1 Management Discussion & Analysis56 Management’s Report57 Independent Auditor’s Report62 Consolidated Financial Statements69 Notes to the Consolidated Financial Statements129 Corporate InformationForward-Looking InformationThis document may contain statements that constitute “forward-lookingstatements” or “forward-looking information” within the meaning ofapplicable 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 identifyforward-looking information, although not all forward-looking informationcontains these identifying words. Specific forward-looking information inthis document includes, but is not limited to: expected future growth andresults of operations; ongoing and planned acquisitions, projects andinitiatives; expectations regarding succession planning; our strategy andgoals, including relating to sustainability; and expectations and plans withrespect to current and planned capital projects. Readers are advised thatall forward-looking information in this document is provided subject tothe cautionary statement regarding forward-looking information, which isfound in Management’s Discussion & Analysis section of this Annual Reportbeginning at page 2.All monetary amounts are in U.S. dollars (US$), except where otherwise noted.

Corporate Profile Algonquin Power & Utilities Corp. (“APUC”) is a diversified international generation, transmission, and distribution utility with approximately $11 billion of total assets. Through its two business groups, APUC is committed to providing safe, reliable, and cost-effective rate-regulated natural gas, water, and electricity generation, transmission, and distribution utility services to approximately 804,000 connections in the United States and Canada, and is a global leader in renewable energy through its portfolio of long-term contracted wind, solar, and hydroelectric generating facilities representing over 2 GW of installed capacity and more than 1.4 GW of incremental renewable energy capacity under construction. APUC strives to deliver reliable earnings, cash flow, and dividend growth through operational excellence and its expanding global pipeline of renewable energy, electric transmission, and water infrastructure development projects, organic growth within its rate-regulated generation, distribution, and transmission businesses, and the pursuit of accretive acquisitions. AlgonquinPowerandUtilities.com TSX/NYSE: AQN

Kenneth Moore Chair of the Board of Directors Ian Robertson Chief Executive Officer Our executive management team is now comprised of 30 per cent female leadership. For 2019, our Total Shareholder Return was 40%, outperforming both the S&P/TSX Composite and S&P/TSX Capped Utilities indices. Letter from the CEO and Chair Dear Fellow Shareholder, At APUC, 2019 was another year of growth, innovation, and success. Nearly 850 MW of new wind and solar projects under construction within our Renewable Energy Group and the advancement of 600 MW of new wind projects in our Regulated Services Group are leading the way to a greener and more sustainable future. We also grew our customer base and expanded our geographic footprint through the successful completion of two new utility acquisitions which added nearly 30,000 customers. Diversity Underscores our Success The theme of diversity continued through 2019 on both the acquisition and organizational fronts. This past year, we completed our first-ever Canadian utility acquisition, New Brunswick Gas, and expanded into New York State with the acquisition of St. Lawrence Gas. We are also proud that APUC was recently recognized in the Bloomberg Gender Equality Index for our commitment to supporting gender equality. In 2019, we welcomed Kirsten Olsen as Chief Human Resources Officer to our executive management team, which is now comprised of 30 per cent female leadership. Strong Financial Results Our proven track record of growing our key financial performance metrics continued in 2019 with year-over-year increases in Adjusted EBITDA, Adjusted Net Earnings, and Adjusted Funds from Operations. As a true testament to our growth program, asset growth increased 16 per cent over 2018 levels as we exited 2019 with nearly $11 billion in total assets. This growth in earnings and cash flows supported the growth in our dividend in 2019, which has now extended to over ten consecutive years of double-digit dividend growth. Finally, we are pleased that APUC has been able to deliver a formidable Total Shareholder Return of 40 per cent in 2019, outperforming both the S&P/TSX Composite and S&P/TSX Capped Utilities indices over the same timeframe. IV AlgonquinPowerandUtilities.com TSX/NYSE: AQN

Executive Succession Plan Throughout 2019, APUC continued to advance its senior leadership succession plan and recently welcomed the addition of Arun Banskota to the newly created position of President. Since joining APUC, Arun has been working closely with APUC executives to expand his knowledge of the business as he prepares to step into the role of Chief Executive Officer in 2020. APUC also announced that long-time Chief Financial Officer, David Bronicheski, has decided to retire in the fall of 2020 and that Arthur Kacprzak has been promoted to Senior Vice President and Deputy Chief Financial Officer. Under Mr. Bronicheski’s leadership, APUC has developed an exceptional finance and treasury team that will strive to continue the strong financial policies that have contributed to APUC’s long-term success. Acting for the Future We remain focused on strengthening our business using conservative building blocks, each of which supports the sustainability and success of our business over the long term. With our five-year strategic plan of identified projects of $9.2 billion in capital, APUC anticipates delivering strong rate base growth, adding over 1.4 GW of sustainable new wind and solar capacity to our generating fleet, and further strengthen our ability to offer creative, cost-effective solutions to our customers. Of course, none of this would be possible without the continued support of our valued stakeholders. We wish to offer our thanks to our diverse team of dedicated power and utility employees for their perseverance and professionalism, our Board of Directors for their thoughtful guidance, and to you, our shareholders, for your trust and support as we continue to grow a business focused on sustaining energy and water for life. Yours Sincerely, Kenneth Moore Chair of the Board of Directors Ian Robertson Chief Executive Officer “We remain focused on strengthening our business using conservative building blocks, each of which supports the sustainability and success of our business over the long term.” APUC 2019 Annual Report V

Founded in 1988 $11 Billion Total Assets 168,000 Water and Wastewater Utility Connections 2,368 Miles of Water Distribution Mains C$9.6 Billion Market Cap* 2,469 Employees World-Wide At a Glance 8,399 Miles of Gas Distribution Lines 774,010 Solar Panels 713 Wind Turbines 267,000 Electric Connections Based in Oakville, Ontario, Canada 11,637 Miles of Electricity Distribution Lines 55 Hydroelectric Generators * Market cap is based on total shares issued and outstanding and the AQN closing price on the NYSE and TSX as at December 31, 2019. 369,000 Gas Utility Connections $7.4 Billion Market Cap* VI AlgonquinPowerandUtilities.com TSX/NYSE: AQN

APUC 2019 Annual Report VII

Financial Highlights (in US$ millions except per share information) Revenue 2019 2018 2017 Generation Revenue $246.6 $235.4 $217.5 Distribution Revenue $1,354.0 $1,391.1 $1,280.4 Other $24.3 $22.0 $24.0 Total Revenue $1,624.9 $1,648.5 $1,521.9 Adjusted EBITDA1 $838.6 $804.4 $689.4 Earnings, Funds from Operations and Dividends Adjusted Funds from Operations1 $566.2 $554.1 $477.1 Adjusted Net Earnings1 $321.3 $312.2 $225.0 Per Share1 $0.63 $0.66 $0.57 Dividends to Shareholders $277.8 $235.4 $185.9 Per Share $0.55 $0.50 $0.47 Balance Sheet Data Total Assets $10,911.5 $9,398.6 $8,395.6 Long-Term Debt (includes current portion) $3,932.2 $3,337.3 $3,080.5 Number of Shares outstanding as of Dec. 31 524,233,323 488,851,433 431,765,935 Renewable Energy Production (% of long-term average) 95% 92% 98% Utility Connections 804,000 768,000 762,000 1. The terms “Adjusted EBITDA”, “Adjusted Net Earnings”, and “Adjusted Funds from Operations” (together, the “Financial Measures”) are used throughout this Annual Report. The Financial Measures are not recognized measures under generally accepted accounting principles in the United States. There is no standardized measure of the Financial Measures, consequently Algonquin’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 further discussion, calculation and analysis of these Financial Measures can be found in the Management Discussion & Analysis section of this Annual Report. VIII AlgonquinPowerandUtilities.com TSX/NYSE: AQN

Strong Financial Position $8,395.6 $9,398.6 $10,911.5 2017 2018 2019 Total Assets (in Millions) $0.55 $566 Million $839 Million $321 Million Further Growth in the Common Share Dividend Adjusted Funds from Operations1 Adjusted Net Earnings1 Adjusted EBITDA1 10% 3% 2% 4% Compelling Total Shareholder Return Jan. 1, 2015 0 50 100 150 200 250 CDN$ Dec. 31, 2015 Dec. 31, 2016 Dec. 31, 2017 Dec. 31, 2018 Dec. 31, 2019 AQN TSX TTUT APUC 2019 Annual Report IX

Algonquin Power & Utilities Corp. Headquarters (Oakville, Ontario, Canada) Regulated Services Group Transmission and distribution utility Rate-based generation Utility investment initiative Expected future acquisition Development/construction project Renewable Energy Group Operating facility Development/construction project X AlgonquinPowerandUtilities.com TSX/NYSE: AQN

Regulated Services Group The Regulated Services Group operates a diversified portfolio of regulated electric, natural gas, water, and wastewater collection utility systems and transmission operations, which collectively serve the needs of approximately 804,000 connections throughout the United States and Canada. The Regulated Services Group seeks to provide safe, high-quality, and reliable services to its customers and to deliver stable and predictable earnings to APUC. In addition to encouraging and supporting organic growth within its service territories, the Regulated Services Group seeks to deliver continued growth in earnings through accretive acquisitions of additional utility systems. 804,000 Connections 40 Utilities 13 U.S. States, 1 Canadian Province $6.8 Billion Regulated Utility Assets Renewable Energy Group The Renewable Energy Group owns and operates a diversified portfolio of non-regulated renewable and clean power generation assets located across Canada and the United States. Its diversified fleet of hydroelectric, wind, solar, and thermal facilities have a combined gross generating capacity of over 2 GW, with approximately 84 per cent of the electrical output sold pursuant to long-term contractual agreements which have a production-weighted average remaining contract life of approximately 14 years. 53 Renewable and Clean Energy Facilities1 >2 GW Installed Capacity1 Global Footprint1 $4.0 Billion Non-regulated Power Assets1 1. Includes APUC’s 44.2% investment in Atlantica Yield plc’s wind and solar assets. APUC 2019 Annual Report XI

Marching to One Million Throughout 2019, APUC made several exciting advancements toward reaching the milestone of servicing one million regulated utility connections. In late 2019, we completed the acquisitions of the St. Lawrence Gas and New Brunswick Gas utilities, which added 17,000 and 12,000 new customer connections, respectively. We also announced two exciting new acquisitions in 2019 – the Bermuda Electric Light Company and New York American Water – which, following the anticipated closing of these acquisitions, are expected to add 160,000 customer connections to our service footprint, bringing our total combined customer count to just under one million customers. Not long ago, our Regulated Services Group solely operated in the United States. We are thrilled that these recent acquisitions have expanded our operations and skill sets beyond those borders to provide residents of New Brunswick, Canada, and eventually Bermuda, with the safe and reliable service on which we pride ourselves. XII AlgonquinPowerandUtilities.com TSX/NYSE: AQN

3 Pillars of Sustainability Social Environment Governance A Leader in Sustainability Sustainability is not just something we do; it’s embedded in who we are. With more than 30 years of experience developing and operating renewable and clean energy facilities, APUC was green long before it was “hip to be green.” We continue to publicly reaffirm this commitment to sustainability. In 2019, we made a conscious decision to showcase our efforts. This past year, we published an updated and modernized sustainability report using the Sustainability Accounting Standards Board (SASB) methodology. We also hosted our inaugural Sustainability Morning, which was impeccably executed by our recently-formed Office of Sustainability. In 2019, APUC continued to make advancements on our “greening the fleet” initiative within our Regulated Services Group. Currently, 600 MW of new wind facilities in the Midwest United States are under construction to replace the recently closed Asbury coal plant at our Empire District Electric Company utility. This is a $1.1 billion initiative that not only reduces carbon emissions, but is also expected to save customers approximately $300 million over the 30-year life of the project. Within our Renewable Energy Group, 2019 saw the advancement of our renewable energy construction and development pipeline. We are pleased to report that construction is underway on 841 MW of our total 1.4 GW pipeline of wind and solar projects that we anticipate will nearly double our portfolio over the coming five years. We are delighted and proud that we are being recognized for our efforts as a leader in sustainability. Recently, APUC was recognized by Corporate Knights among its list of Global 100 Most Sustainable Corporations, ranking within the top 10 – the highest-ranked Canadian company and the highest-ranked electric utility on the list. Through our decarbonization initiatives and growth in renewables, our organization remains well positioned to capitalize on the growth of renewable energy as sustainability becomes an increasingly relevant and important metric of success. Our commitment to championing and investing in renewable energy positions APUC as a leader in the transition toward sustainable energy and water for life. 1,442 megawatt of projects We hosted our inaugural Sustainability Morning Ranked #10 most sustainable corporation in the world by the Corporate Knights APUC 2019 Annual Report XIII

How We Create Value Build for the Future Everything we do is directed to making a lasting difference. From powering your stove, filling up your bath, to generating clean energy for regions and communities, we provide critical services that are needed by everyone, day in and day out. We are committed to providing everyone access to affordable, reliable, sustainable, and modern energy and water services today, so we can enjoy a clean future tomorrow. We Act for Our Environment North America is actively transitioning into a sustainable, low-carbon economy and we are at the forefront of that transition. Our strategy stems from the United Nations Sustainable Development Goals and we are taking tangible action to reduce the environmental impacts of our daily operations and the services we deliver. Inspire Our Communities We exist for the people we serve – our customers, our people, and our shareholders. Many of us live in the communities we serve. We work with our customers, local partners, regulators, and interested parties in our communities to combat the climate change challenge. We have clear environmental, social, and governance goals to build the foundation for a sustainable and prosperous future. XIV AlgonquinPowerandUtilities.com TSX/NYSE: AQN

Management Discussion & Analysis
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, 2019. This Management Discussion & Analysis (“MD&A”) should be read in conjunction with APUC’s annual audited consolidated financial statements for the years ended December 31, 2019 and 2018. This material is available on SEDAR at www.sedar.com, on EDGAR at www.sec.gov/edgar, 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 and on EDGAR at www.sec.gov/edgar.
Unless otherwise indicated, financial information provided for the years ended December 31, 2019 and 2018 has been prepared in accordance with generally accepted accounting principles in the United States (“U.S. GAAP”). As a result, the Company’s financial information may not be comparable with financial information of other Canadian companies that provide financial information on another basis.
All monetary amounts are in thousands of U.S. dollars, except where otherwise noted. We denote any amounts denominated in Canadian dollars with “C$” immediately prior to the stated amount.
This MD&A is based on information available to management as of February 27, 2020.
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 information” within the meaning of applicable securities laws in each of the provinces of Canada and the respective policies, regulations and rules under such laws or “forward-looking statements” within the meaning of the U.S. Private Securities Litigation Reform Act of 1995 (collectively, “forward-looking information”). The words “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 is not limited to, statements relating to: expected future growth and results of operations; liquidity, capital resources and operational requirements; rate reviews, 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; expectations regarding the use of proceeds from equity financing, including the Offering and the ATM Program (each as defined herein); ongoing and planned acquisitions, projects and initiatives, including expectations regarding costs, financing, results and completion dates; expectations regarding the anticipated closing of APUC’s acquisitions of Ascendant and New York American Water (each as defined herein); expectations regarding the Company’s corporate development activities and the results thereof including the expected business mix between the Regulated Services Group and Renewable Energy Group; expectations regarding regulatory hearings, motions and approvals; 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, sources of funds 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; expectations regarding succession planning; contractual obligations and other commercial commitments; environmental liabilities; dividends to shareholders; expectations regarding the maturity and redemption of APUC’s outstanding subordinated notes; 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.

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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 or supply chain disruptions or liability due to natural disasters, diseases 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; failure to identify, acquire, develop or timely place in service projects to maximize the value of production tax credit qualified equipment; 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, including as a result of the 2019 novel coronavirus outbreak in China (the “2019 Novel Coronavirus”); loss of key customers; failure to realize the anticipated benefits of acquisitions or joint ventures; Atlantica (as defined herein) or the Corporation’s joint venture with Abengoa S.A (MC:ABG) (“Abengoa”), Abengoa-Algonquin Global Energy Solutions (“AAGES”), acting in a manner contrary to the Corporation’s interests; a drop in the market value of Atlantica’s ordinary shares; facilities being condemned or otherwise taken by governmental entities; increased external-stakeholder activism adverse to the Corporation’s interests; 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 most recent 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.

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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
Adjusted 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, non-service pension and post-employment costs, cost related to tax equity financing, gain or loss on foreign exchange, earnings or loss from discontinued operations, changes in value of investments carried at fair value, and other typically non-recurring 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, and can be impacted positively or negatively by these items.
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 (other than those realized in connection with the sales of development assets), changes in value of investments carried at fair value, and other typically non-recurring items as these are not reflective of the performance of the underlying business of APUC. The Non-cash accounting charge related to the revaluation of U.S. deferred income tax assets and liabilities as a result of implementation of the effects of the Tax Cuts and Jobs Act (“U.S. Tax Reform”) 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. Adjusted Net Earnings is not intended to be representative of net earnings or loss determined in accordance with U.S. GAAP, and can be impacted positively or negatively by these items.
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 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. Adjusted Funds from Operations is not intended to be representative of cash flows from operating activities as determined in accordance with U.S. GAAP, and can be impacted positively or negatively by these items.

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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, gain or loss on foreign exchange, earnings or loss from discontinued operations, non-service pension and post-employment costs, 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 interest, dividend and equity income earned from indirect investments, and Hypothetical Liquidation at Book Value (“HLBV”) income, which represents the value of net tax attributes earned in the period from electricity generated by certain of its U.S. wind power and U.S. solar generation facilities. 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.

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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 strives to achieve these results while also seeking to maintain a business risk profile consistent with its BBB flat investment grade credit ratings and a strong focus on Environmental, Social and Governance factors.
APUC’s current quarterly dividend to shareholders is $0.1410 per common share or $0.5640 per common share per annum. Based on exchange rates as at February 26, 2020, the quarterly dividend is equivalent to C$0.1876 per common share or C$0.7504 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 APUC’s financial performance and growth prospects.
APUC’s operations are organized across two primary business units consisting of: the Regulated Services Group, which primarily owns and operates a portfolio of regulated assets in the United States and Canada, and the Renewable Energy Group, which primarily owns and operates a diversified portfolio of renewable generation assets.
APUC pursues investment opportunities with an objective of maintaining the current business mix between its Regulated Services Group and Renewable Energy Group and with leverage consistent with its current credit ratings1. The business mix target may from time to time require APUC to grow its Regulated Services Group or implement other strategies in order to pursue investment opportunities within its Renewable Energy Group.
The Company also undertakes development activities for both business units, working with a global reach to identify, develop, acquire, or invest in renewable power generating facilities, regulated utilities and other complementary infrastructure projects. See additional discussion in Corporate Development Activities.
Summary Organizational Structure
The following represents a summarized organizational chart for APUC. A more detailed description of APUC’s organizational structure can be found in the most recent AIF.

1 | See Treasury Risk Management -Downgrade in the Company’s Credit Rating Risk
2 | Algonquin Power Co. dba Liberty Power

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Regulated Services Group
The Regulated Services Group operates a diversified portfolio of regulated utility systems throughout the United States and Canada serving approximately 804,000 connections. The Regulated Services Group seeks to provide safe, high quality, and reliable services to its customers and to deliver stable and predictable earnings to APUC. In addition to encouraging and supporting organic growth within its service territories, the Regulated Services Group seeks to deliver continued growth in earnings through accretive acquisitions of additional utility systems.
The Regulated Services 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 which together serve approximately 267,000 electric connections. The group also owns and manages generating assets with a gross capacity of approximately 1.7 GW and has investments in generating assets with approximately 0.3 GW of net generation capacity.
The Regulated Services Group’s regulated natural gas distribution utility systems are located in the States of Georgia, Illinois, Iowa, Massachusetts, New Hampshire, Missouri, New York, and the Province of New Brunswick which together serve approximately 369,000 natural gas connections.
The Regulated Services 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 168,000 connections.
Renewable Energy Group
The Renewable Energy Group generates and sells electrical energy produced by its diverse portfolio of renewable power generation and clean power generation facilities primarily located across the United States and Canada. The Renewable Energy Group seeks to deliver continuing growth through development of new greenfield power generation projects and accretive acquisitions of additional electrical energy generation facilities.
The Renewable Energy Group owns and operates hydroelectric, wind, solar, and thermal facilities with a combined gross generating capacity of approximately 1.5 GW. Approximately 84% of the electrical output is sold pursuant to long term contractual arrangements which as of December 31, 2019 had a production-weighted average remaining contract life of approximately 14 years.
In addition to directly owned and operated assets, APUC also holds a 44.2% interest in Atlantica Yield PLC (“Atlantica”). Atlantica owns and operates a portfolio of international clean energy and water infrastructure assets under long term contracts with a Cash Available for Distribution (CAFD) weighted average remaining contract life of approximately 18 years as of December 31, 2019.

Management Discussion & Analysis – APUC 2019 Annual Report | 6

2019 Major Highlights
Corporate Highlights
Operating Results
APUC operating results relative to the same period last year are as follows:

(all dollar amounts in $ millions except per share information) | Three Months Ended December 31 |  | Twelve Months Ended December 31
2019 |  | 2018 |  | Change |  | 2019 |  | 2018 |  | Change
Net earnings attributable to shareholders | $172.1 |  | $44.0 |  | 291% |  | $530.9 |  | $185.0 |  | 187%
Adjusted Net Earnings1 | $103.6 |  | $70.5 |  | 47% |  | $321.3 |  | $312.2 |  | 3%
Adjusted EBITDA1 | $231.5 |  | $198.9 |  | 16% |  | $838.6 |  | $804.4 |  | 4%
Net earnings per common share | $0.34 |  | $0.09 |  | 278% |  | $1.05 |  | $0.38 |  | 176%
Adjusted Net Earnings per common share1 | $0.20 |  | $0.14 |  | 43% |  | $0.63 |  | $0.66 |  | (5)%

1 | See Non-GAAP Financial Measures.

Declaration of 2020 First Quarter Dividend of $0.1410 (C$0.1876) per Common Share
APUC currently targets annual growth in dividends payable to shareholders underpinned by increases in earnings and cash flow. In setting the appropriate dividend level, the Board of APUC considers the Company’s current and expected growth in earnings per share as well as a dividend payout ratio as a percentage of earnings per share and cash flow per share.
On February 27, 2020, APUC announced that the Board of APUC declared a first quarter 2020 dividend of $0.1410 per common share payable on April 15, 2020 to shareholders of record on March 31, 2020. Based on the prior day Bank of Canada exchange rate, the Canadian dollar equivalent for the first quarter 2020 dividend is set at C$0.1876 per common share.
The previous four quarter equivalent Canadian dollar dividends per common share have been as follows:

| Q2 2019 | Q3 2019 | Q4 2019 | Q1 2020 | Total
U.S. dollar dividend | $0.1410 | $0.1410 | $0.1410 | $0.1410 | $0.5640
Canadian dollar equivalent | $0.1899 | $0.1878 | $0.1858 | $0.1876 | $0.7511

Corporate Financings Completed
Issuance of Fixed-to-Floating Subordinated Notes
On May 23, 2019, APUC issued $350.0 million of 60 (non-call 5) year fixed-to-floating 6.20% subordinated notes (“Notes”). Concurrent with the offering, APUC entered into a cross currency swap to convert the U.S. dollar denominated coupon and principal payments from the offering into Canadian dollars, resulting in an effective interest rate to the Company throughout the fixed-rate period of the Notes of approximately 5.96%. This offering represents APUC’s second issuance into the U.S. public debt markets (see Long Term Debt).
Common Equity Financing
In October 2019, APUC sold approximately 26.3 million of its common shares at a price of $13.50 by way of an underwritten marketed public offering (the “Offering”) for total gross proceeds of approximately $354.4 million. The Offering primarily targeted U.S. investors. The proceeds of the Offering were or will be used (as applicable) to partially finance certain of the Company’s previously announced acquisitions, to partially finance the Company’s renewable development growth projects, and for general corporate purposes.
Regulated Services Group Highlights
Definitive Agreement to Acquire Bermuda Electric Light Company
On June 3, 2019, APUC announced it had agreed to acquire the Ascendant Group Limited (“Ascendant”) (BSX: AGL.BH) for a purchase price of $36.00 per common share, representing an aggregate share purchase price of approximately $365.0 million (the “Ascendant Transaction”). Ascendant, through its major subsidiary, Bermuda Electric Light Company (“BELCO”), is the sole electric utility providing safe and reliable regulated electrical generation, transmission and distribution services to approximately 63,000 residents and businesses in Bermuda. Approval of Ascendant’s common shareholders has been received

Management Discussion & Analysis – APUC 2019 Annual Report | 7

and the closing of the Ascendant Transaction is expected to occur in 2020 subject to customary closing conditions, including the receipt of certain regulatory and government approvals in Bermuda.
Acquisition of Ownership Interest in Wataynikaneyap Power Transmission Project
On January 17, 2019, the Regulated Services Group acquired from Fortis Inc. a 9.8% ownership interest in an electricity transmission project located in Northwestern Ontario (the “Wataynikaneyap Power Transmission Project”) that is expected to connect 17 remote First Nation communities to the Ontario provincial electricity grid through the construction of approximately 1,800 km of transmission lines. In addition to providing participating First Nations communities ownership in the transmission line, the Wataynikaneyap Power Transmission Project is expected to result in socio-economic benefits for surrounding communities, reduce environmental risk, and lessen greenhouse gas emissions associated with diesel-fired generation currently used in that area.
In April 2019, the Ontario Energy Board approved the leave-to-construct application. Completion of construction financing and issuance of notice to proceed to the EPC contractor occurred in October 2019. The Wataynikaneyap Power Transmission Project is targeted to be complete by the end of 2023.
Significant Milestones Achieved on Mid-West Wind Development Project
In June 2019, the Regulated Services Group received certificates of convenience and necessity (“CC&N”) to acquire, once completed, three wind farms generating up to 600 MW of wind energy located in Barton, Dade, Lawrence, and Jasper Counties in Missouri and in Neosho County, Kansas.
Receipt of the CC&N’s allows construction to commence on the three wind generation sites. Construction of two of the wind farms began in the fourth quarter of 2019 and construction on the third wind farm began in the first quarter of 2020 (see Corporate Development Activities).
Acquisition of New Brunswick Gas
On October 1, 2019, APUC completed the acquisition of the Enbridge Gas New Brunswick Limited Partnership (“New Brunswick Gas” or the “New Brunswick Gas System”) for approximately C$339.0 million. New Brunswick Gas is a regulated utility that provides natural gas to approximately 12,000 customers in 12 communities across New Brunswick, and operates approximately 1,200 km of natural gas distribution pipeline.
Issuance of C$200 of senior unsecured debentures
Subsequent to year-end on February 14, 2020, Liberty Utilities (Canada) LP, the holding company of New Brunswick Gas, issued C$200.0 million of senior unsecured debentures bearing interest at 3.315% and with a maturity date of February 14, 2050. The debentures received a rating of BBB from DBRS. The proceeds were used to repay corporate credit facilities drawn in connection with the closing of New Brunswick Gas (see Long Term Debt).
Acquisition of St. Lawrence Gas
On November 1, 2019, the Regulated Services Group completed the acquisition of the St. Lawrence Gas Company Inc. (“St. Lawrence Gas” or the “St. Lawrence Gas System”) for approximately $61.8 million. St. Lawrence Gas is a regulated utility that provides natural gas to approximately 17,000 customers in the state of New York and operates approximately 1,100 km of natural gas distribution pipeline.
Definitive Agreement to Acquire New York American Water
On November 20, 2019, APUC announced that it entered into a stock purchase agreement with American Water Works Company, Inc. (NYSE: AWK) (“American Water”), to purchase American Water’s regulated operations in the State of New York (“New York American Water”) for a purchase price of $608.0 million, subject to customary adjustments. New York American Water is a regulated water and wastewater utility serving over 125,000 customer connections across seven counties in southeastern New York. Operations include approximately 1,270 miles of water mains and distributions lines with 98% of customers located in Nassau County on Long Island. The transaction remains subject to regulatory approval and other typical closing conditions and is expected to close sometime in 2021.
Successful Rate Review Outcomes
A core strategy of the Regulated Services Group is to ensure an appropriate return is earned on the rate base at its various utility systems. During 2019, the Regulated Services Group successfully completed several rate reviews representing a cumulative annualized revenue increase of approximately $8.5 million. In addition progress was made in advancing several regulatory mechanisms.

Management Discussion & Analysis – APUC 2019 Annual Report | 8

Renewable Energy Group’s Highlights
Issuance of Green Bonds
On January 29, 2019, the Renewable Energy Group issued C$300.0 million of senior unsecured debentures bearing interest at 4.60% and with a maturity date of January 29, 2029. The debentures represent the Renewable Energy Group’s inaugural “green bond” offering (see Long Term Debt).
Maverick Creek Wind Project Joint Venture
On August 8, 2019, the Renewable Energy Group agreed to jointly develop the approximately 490 MW Maverick Creek Wind Project located in Concho County, Texas with Renewable Energy Systems Americas Inc.
2019 Fourth Quarter Results From Operations

Key Financial Information | Three Months Ended December 31
(all dollar amounts in $ millions except per share information) | 2019 |  | 2018
Revenue | $ | 439.7 |  |  | $ | 421.9 |
Net earnings attributable to shareholders | 172.1 |  |  | 44.0 |
Cash provided by operating activities | 167.5 |  |  | 168.6 |
Adjusted Net Earnings1 | 103.6 |  |  | 70.5 |
Adjusted EBITDA1 | 231.5 |  |  | 198.9 |
Adjusted Funds from Operations1 | 144.1 |  |  | 132.5 |
Dividends declared to common shareholders | 74.3 |  |  | 63.1 |
Weighted average number of common shares outstanding | 519,846,220 |  |  | 477,450,181 |
Per share |  |  |
Basic net earnings | $ | 0.34 |  |  | $ | 0.09 |
Diluted net earnings | $ | 0.33 |  |  | $ | 0.09 |
Adjusted Net Earnings1,2 | $ | 0.20 |  |  | $ | 0.14 |
Dividends declared to common shareholders | $ | 0.14 |  |  | $ | 0.13 |

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, 2019, APUC experienced an average exchange rate of Canadian to U.S. dollars of approximately 0.7576 as compared to 0.7568 in the same period in 2018. As such, any quarter over quarter variance in revenue or expenses, in local currency, at any of APUC’s Canadian 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, 2019, APUC reported total revenue of $439.7 million as compared to $421.9 million during the same period in 2018, an increase of $17.8 million. The major factors resulting in the increase in APUC revenue in the three months ended December 31, 2019 as compared to the corresponding period in 2018 are set out as follows:

Management Discussion & Analysis – APUC 2019 Annual Report | 9

(all dollar amounts in $ millions) | Three Months Ended December 31
Comparative Prior Period Revenue | $ | 421.9 |
REGULATED SERVICES GROUP |
Existing Facilities |
Electricity: Decrease is primarily due to lower pass through commodity costs and lower consumption as a result of warmer weather compared to the prior year at the Empire Electric and Granite State Electric Systems. | (11.6 | )
Gas: Decrease is primarily due to lower pass through commodity costs at the Midstates, EnergyNorth, New England and Empire Gas Systems. | (8.7 | )
Water: Increase is primarily due to higher revenues resulting from organic growth at the White Hall and Litchfield Park Water Systems. | 1.8 |
Other: Increase in contracted services from Ft. Benning. | 2.8 |
| (15.7 | )
New Facilities |
Gas: Acquisitions of New Brunswick Gas (October 2019) and St. Lawrence Gas (November 2019). | 24.5 |
| 24.5 |
Rate Reviews |
Electricity: Implementation of new rates at the Granite State Electric System. | 0.3 |
Water: Implementation of lower rates at the Park Water System due to U.S. Tax Reform, partially offset by higher rates at the Tall Timbers Water System, net of U.S. Tax Reform impact. | (0.2 | )
| 0.1 |
RENEWABLE ENERGY GROUP |
Existing Facilities |
Hydro: Decrease is primarily due to lower production at the Quebec and Ontario Regions. | (1.0 | )
Wind Canada: Increase is primarily due to annual rate increases and higher production at the St. Leon Wind Facility. | 1.1 |
Wind U.S.: Increase is primarily due to higher production. | 1.8 |
Solar U.S.: Increase is primarily due to higher production at the Bakersfield Solar Facilities as well as favorable Renewable Energy Credit (“REC”) pricing at Great Bay Solar Facility. | 0.6 |
Thermal: Decrease is primarily due to lower production and unfavorable capacity pricing at the Windsor Locks Thermal Facility. | (1.7 | )
Other | 0.4 |
| 1.2 |
New Facilities |
Wind Canada: The Amherst Island Wind Facility was previously accounted for as an equity investment. | 7.7 |
| 7.7 |
Current Period Revenue | $ | 439.7 |

A more detailed discussion of these factors is presented within the business unit analysis.
For the three months ended December 31, 2019, net earnings attributable to shareholders totaled $172.1 million as compared to $44.0 million during the same period in 2018, an increase of $128.1 million or 291.1%. The increase was due to a $21.3 million increase in earnings from operating facilities, a $144.1 million change in fair value of investments carried at fair value, a $10.6 million increase in interest, dividend, equity and other income, a $9.4 million increase in net effect of non-controlling interests and a $0.2 million increase in gains from derivative instruments. These items were partially offset by a $7.1 million increase in interest expense, a $13.9 million increase in depreciation and amortization expenses, a $15.3 million increase in acquisition related costs, a $5.0 million increase in pension and post-employment non-service costs, a $0.2 million increase in administration charges, a $2.4 million increase in foreign exchange losses, and a $9.7 million increase in income tax expense (tax explanations are discussed in APUC: Corporate and Other Expenses) as compared to the same period in 2018.

Management Discussion & Analysis – APUC 2019 Annual Report | 10

During the three months ended December 31, 2019, cash provided by operating activities totaled $167.5 million as compared to $168.6 million during the same period in 2018. During the three months ended December 31, 2019, Adjusted Funds from Operations totaled $144.1 million as compared to Adjusted Funds from Operations of $132.5 million during the same period in 2018 (see Non-GAAP Financial Measures).
During the three months ended December 31, 2019, Adjusted EBITDA totaled $231.5 million as compared to $198.9 million during the same period in 2018, an increase of $32.6 million or 16.4%. 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).
2019 Annual Results From Operations

Key Financial Information | Twelve Months Ended December 31
(all dollar amounts in $ millions except per share information) | 2019 |  | 2018 |  | 2017
Revenue | $ | 1,624.9 |  |  | $ | 1,648.5 |  |  | $ | 1,521.9 |
Net earnings attributable to shareholders | 530.9 |  |  | 185.0 |  |  | 149.5 |
Cash provided by operating activities | 611.3 |  |  | 530.4 |  |  | 326.6 |
Adjusted Net Earnings1 | 321.3 |  |  | 312.2 |  |  | 225.0 |
Adjusted EBITDA1 | 838.6 |  |  | 804.4 |  |  | 689.4 |
Adjusted Funds from Operations1 | 566.2 |  |  | 554.1 |  |  | 477.1 |
Dividends declared to common shareholders | 277.8 |  |  | 235.4 |  |  | 185.9 |
Weighted average number of common shares outstanding | 499,910,876 |  |  | 461,818,023 |  |  | 382,323,434 |
Per share |  |  |  |  |
Basic net earnings | $ | 1.05 |  |  | $ | 0.38 |  |  | $ | 0.37 |
Diluted net earnings | $ | 1.04 |  |  | $ | 0.38 |  |  | $ | 0.37 |
Adjusted Net Earnings1,2 | $ | 0.63 |  |  | $ | 0.66 |  |  | $ | 0.57 |
Dividends declared to common shareholders | $ | 0.55 |  |  | $ | 0.50 |  |  | $ | 0.47 |
Total assets | 10,911.5 |  |  | 9,398.6 |  |  | 8,395.6 |
Long term debt3 | 3,932.2 |  |  | 3,337.3 |  |  | 3,080.5 |

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, 2019, APUC experienced an average exchange rate of Canadian to U.S. of approximately 0.7537 as compared to 0.7715 in the same period in 2018. As such, any year-over-year variance in revenue or expenses, in local currency, at any of APUC’s Canadian 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, 2019, APUC reported total revenue of $1,624.9 million as compared to $1,648.5 million during the same period in 2018, a decrease of $23.6 million or 1.4%. The major factors resulting in the decrease in APUC revenue for the twelve months ended December 31, 2019 as compared to the corresponding period in 2018 are set out as follows:

Management Discussion & Analysis – APUC 2019 Annual Report | 11

(all dollar amounts in $ millions) | Twelve Months Ended December 31
Comparative Prior Period Revenue | $ | 1,648.5 |
REGULATED SERVICES GROUP |
Existing Facilities |
Electricity: Decrease is primarily due to lower pass through commodity costs at the Empire Electric System. | (33.8 | )
Gas: Decrease is primarily due to lower pass through commodity costs at the Midstates, EnergyNorth, New England and Empire Gas Systems. | (21.8 | )
Water: Increase is primarily due to higher revenues resulting from organic growth at the Litchfield Park Water System as well as the acquisition of several small water utilities throughout the year. | 2.6 |
Other: Increase in contracted services from Ft. Benning. | 2.6 |
| (50.4 | )
New Facilities |
Gas: Acquisitions of New Brunswick Gas (October 2019) and St. Lawrence Gas (November 2019). | 24.5 |
| 24.5 |
Rate Reviews |
Electricity: Implementation of lower rates at the Empire Electric System due to U.S. Tax Reform. | (13.0 | )
Gas: Implementation of new rates, net of U.S. Tax Reform impact, primarily at the Midstates and EnergyNorth Gas Systems, partially offset by lower rates at the Empire Gas System due to U.S. Tax Reform. | 5.0 |
Water: Implementation of lower rates at the Park Water System due to U.S. Tax Reform, partially offset by new rates, net of U.S. Tax Reform impact, at the Litchfield Park Water System. | (0.6 | )
| (8.6 | )
RENEWABLE ENERGY GROUP |
Existing Facilities |
Hydro: Increase is primarily due to higher production. | 0.2 |
Wind Canada: Increase is primarily due to annual rate increases and higher production at the St. Leon Wind Facility. | 2.1 |
Wind U.S.: Increase is primarily due to higher production, partially offset by unfavorable market pricing during periods with low wind resources at the Senate Wind Facility as well as lower REC rates at the Minonk Wind Facility. | 0.4 |
Solar Canada: Increase is primarily due to higher production. | 0.2 |
Thermal: Decrease is primarily due lower production. | (8.7 | )
Other | 0.5 |
| (5.3 | )
New Facilities |
Wind Canada: Amherst Island Wind Facility achieved commercial operations (“COD”) in June 2018. | 15.9 |
Solar U.S.: Great Bay Solar Facility achieved full COD in March 2018. | 2.0 |
| 17.9 |
Foreign Exchange | (1.7 | )
Current Period Revenue | $ | 1,624.9 |

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

Management Discussion & Analysis – APUC 2019 Annual Report | 12

For the twelve months ended December 31, 2019, net earnings attributable to shareholders totaled $530.9 million as compared to $185.0 million during the same period in 2018, an increase of $345.9 million. The increase was due to a $17.7 million increase in earnings from operating facilities, a $67.9 million increase in interest, dividend, equity and other income, a $416.1 million change in fair value of investments carried at fair value, and a $16.7 million increase on gains from derivative instruments. These items were partially offset by a $29.4 million increase in interest expense, a $23.5 million increase in depreciation and amortization expenses, a $12.3 million increase in pension and post-employment non-service costs, a $10.9 million increase in acquisition costs, a $4.1 million increase in administration charges, a $12.4 million increase in other losses, a $3.2 million increase in foreign exchange losses, a $60.0 million decrease in net effect of non-controlling interests, and a $16.7 million increase in income tax expense (tax explanations are discussed in APUC: Corporate and Other Expenses).
During the twelve months ended December 31, 2019, cash provided by operating activities totaled $611.3 million as compared to $530.4 million during the same period in 2018. During the twelve months ended December 31, 2019, Adjusted Funds from Operations, totaled $566.2 million as compared to $554.1 million the same period in 2018, an increase of $12.1 million (see Non-GAAP Financial Measures).
Adjusted EBITDA in the twelve months ended December 31, 2019 totaled $838.6 million as compared to $804.4 million during the same period in 2018, an increase of $34.2 million or 4.3%. 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).

Management Discussion & Analysis – APUC 2019 Annual Report | 13

2019 Adjusted EBITDA Summary
Adjusted EBITDA (see Non-GAAP Financial Measures) for the three months ended December 31, 2019 totaled $231.5 million as compared to $198.9 million during the same period in 2018, an increase of $32.6 million or 16.4%. Adjusted EBITDA for the twelve months ended December 31, 2019 totaled $838.6 million as compared to $804.4 million during the same period in 2018, an increase of $34.2 million or 4.3%. In the first quarter of 2018, APUC recorded a one-time acceleration of HLBV income of $55.9 million. Excluding this adjustment, Adjusted EBITDA increased by $90.1 million year over year. 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) | 2019 |  | 2018 |  | 2019 |  | 2018
Regulated Services Group Operating Profit | $ | 160.5 |  |  | $ | 135.0 |  |  | $ | 565.4 |  |  | $ | 551.6 |
Renewable Energy Group Operating Profit | 85.9 |  |  | 78.7 |  |  | 328.5 |  |  | 303.6 |
Administrative Expenses | (15.2 | ) |  | (15.0 | ) |  | (56.8 | ) |  | (52.7 | )
Other Income & Expenses | 0.3 |  |  | 0.2 |  |  | 1.5 |  |  | 1.9 |
Total APUC Adjusted EBITDA | $ | 231.5 |  |  | $ | 198.9 |  |  | $ | 838.6 |  |  | $ | 804.4 |
Change in Adjusted EBITDA ($) | $ | 32.6 |  |  |  |  | $ | 34.2 |  |  |
Change in Adjusted EBITDA (%) | 16.4 | % |  |  |  | 4.3 | % |  |

Change in Adjusted EBITDA | Three Months Ended December 31, 2019
(all dollar amounts in $ millions) | Regulated Services | Renewable Energy |  | Corporate | Total
Prior period balances | $ | 135.0 |  | $ | 78.7 |  |  | $ | (14.8 | ) | $ | 198.9 |
Existing Facilities | 17.9 |  | 1.6 |  |  | 0.1 |  | 19.6 |
New Facilities and Investments | 7.5 |  | 5.5 |  |  | — |  | 13.0 |
Rate Reviews | 0.1 |  | — |  |  | — |  | 0.1 |
Foreign Exchange Impact | — |  | 0.1 |  |  | — |  | 0.1 |
Administrative Expenses | — |  | — |  |  | (0.2 | ) | (0.2 | )
Total change during the period | $ | 25.5 |  | $ | 7.2 |  |  | $ | (0.1 | ) | $ | 32.6 |
Current period balances | $ | 160.5 |  | $ | 85.9 |  |  | $ | (14.9 | ) | $ | 231.5 |

Change in Adjusted EBITDA | Twelve Months Ended December 31, 2019
(all dollar amounts in $ millions) | Regulated Services | Renewable Energy |  | Corporate | Total
Prior period balances | $ | 551.6 |  | $ | 303.6 |  |  | $ | (50.8 | ) | $ | 804.4 |
Existing Facilities | 14.9 |  | (49.1 | ) | 1 | (0.4 | ) | (34.6 | )
New Facilities and Investments | 7.5 |  | 75.3 |  |  | — |  | 82.8 |
Rate Reviews | (8.6 | ) | — |  |  | — |  | (8.6 | )
Foreign Exchange Impact | — |  | (1.3 | ) |  | — |  | (1.3 | )
Administration Expenses | — |  | — |  |  | (4.1 | ) | (4.1 | )
Total change during the period | $ | 13.8 |  | $ | 24.9 |  |  | $ | (4.5 | ) | $ | 34.2 |
Current period balances | $ | 565.4 |  | $ | 328.5 |  |  | $ | (55.3 | ) | $ | 838.6 |

1 | Includes a one-time acceleration of HLBV income of $55.9 million recorded in the first quarter of 2018 due to U.S. Tax Reform.

Management Discussion & Analysis – APUC 2019 Annual Report | 14

REGULATED SERVICES GROUP
The Regulated Services Group operates rate-regulated utilities that provide distribution services to approximately 804,000 connections in the natural gas, electric, and water and wastewater sectors which is an increase of 36,000 connections as compared to the prior year. On October 1, 2019, with the acquisition of the New Brunswick Gas System, the Regulated Services Group expanded its footprint into Canada and added an additional 12,000 connections. On November 1, 2019, with the acquisition of the St. Lawrence Gas System, the Regulated Services Group added an additional 17,000 connections in New York State. The Regulated Services Group’s strategy is to grow its business organically and through business development activities while using prudent acquisition criteria. The Regulated Services Group believes that its business results are maximized by building constructive regulatory and customer relationships, and enhancing connections in the communities in which it operates.

Utility System Type | As at December 31
2019 | 2018
(all dollar amounts in $ millions) | Assets | Total Connections 1 | Assets | Total Connections 1
Electricity | $ | 2,792.4 |  | 267,000 |  | $ | 2,599.7 |  | 266,000 |
Natural Gas | $ | 1,377.3 |  | 369,000 |  | $ | 1,088.3 |  | 338,000 |
Water and Wastewater | $ | 513.6 |  | 168,000 |  | $ | 481.9 |  | 164,000 |
Other | $ | 71.0 |  |  | $ | 40.2 |  |
Total | $ | 4,754.3 |  | 804,000 |  | $ | 4,210.1 |  | 768,000 |
Accumulated Deferred Income Taxes Liability | 474.0 |  |  | $ | 438.4 |  |

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

The Regulated Services Group aggregates the performance of its utility operations by utility system type – electricity, natural gas, and water and wastewater systems.
The electric distribution systems are comprised of regulated electrical distribution utility systems and serve approximately 267,000 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 369,000 connections located in the States of New Hampshire, Illinois, Iowa, Missouri, Georgia, Massachusetts, New York, and in the Province of New Brunswick.
The water and wastewater distribution systems are comprised of regulated water distribution and wastewater collection utility systems and serve approximately 168,000 connections located in the States of Arkansas, Arizona, California, Illinois, Missouri and Texas. Approximately 4,000 new customers were added through organic growth and from acquisitions of small water utilities compared to the previous year.
2019 Annual Usage Results

Electric Distribution Systems | Three Months Ended December 31 |  | Twelve Months Ended December 31
| 2019 |  | 2018 |  | 2019 |  | 2018
Average Active Electric Connections For The Period |  |  |  |  |  |  |
Residential | 228,000 |  |  | 225,900 |  |  | 227,200 |  |  | 225,200 |
Commercial and industrial | 38,100 |  |  | 37,900 |  |  | 38,100 |  |  | 37,800 |
Total Average Active Electric Connections For The Period | 266,100 |  |  | 263,800 |  |  | 265,300 |  |  | 263,000 |
Customer Usage (GW-hrs) |  |  |  |  |  |  |
Residential | 599.7 |  |  | 611.2 |  |  | 2,488.1 |  |  | 2,535.1 |
Commercial and industrial | 932.1 |  |  | 971.2 |  |  | 3,944.5 |  |  | 3,988.9 |
Total Customer Usage (GW-hrs) | 1,531.8 |  |  | 1,582.4 |  |  | 6,432.6 |  |  | 6,524.0 |

For the three months ended December 31, 2019, the electric distribution systems’ usage totaled 1,531.8 GW-hrs as compared to 1,582.4 GW-hrs for the same period in 2018, a decrease of 50.6 GW-hrs or 3.2%.

Management Discussion & Analysis – APUC 2019 Annual Report | 15

For the twelve months ended December 31, 2019, the electric distribution systems’ usage totaled 6,432.6 GW-hrs as compared to 6,524.0 GW-hrs for the same period in 2018, a decrease of 91.4 GW-hrs or 1.4%.

Natural Gas Distribution Systems | Three Months Ended December 31 |  | Twelve Months Ended December 31
| 2019 |  | 2018 |  | 2019 |  | 2018
Average Active Natural Gas Connections For The Period |  |  |  |  |  |  |
Residential | 302,700 |  |  | 288,900 |  |  | 303,100 |  |  | 288,700 |
Commercial and industrial | 35,700 |  |  | 31,700 |  |  | 35,600 |  |  | 31,700 |
Total Average Active Natural Gas Connections For The Period | 338,400 |  |  | 320,600 |  |  | 338,700 |  |  | 320,400 |
Customer Usage (MMBTU) |  |  |  |  |  |  |
Residential | 6,341,000 |  |  | 6,186,000 |  |  | 20,213,000 |  |  | 20,065,000 |
Commercial and industrial | 5,969,000 |  |  | 4,533,000 |  |  | 15,676,000 |  |  | 14,529,000 |
Total Customer Usage (MMBTU) | 12,310,000 |  |  | 10,719,000 |  |  | 35,889,000 |  |  | 34,594,000 |

For the three months ended December 31, 2019, usage at the natural gas distribution systems totaled 12,310,000 MMBTU as compared to 10,719,000 MMBTU during the same period in 2018, an increase of 1,591,000 MMBTU, or 14.8%.
For the twelve months ended December 31, 2019, usage at the natural gas distribution systems totaled 35,889,000 MMBTU as compared to 34,594,000 MMBTU during the same period in 2018, an increase of 1,295,000 MMBTU or 3.7%.

Water and Wastewater Distribution Systems | Three Months Ended December 31 |  | Twelve Months Ended December 31
| 2019 |  | 2018 |  | 2019 |  | 2018
Average Active Connections For The Period |  |  |  |  |  |  |
Wastewater connections | 44,400 |  |  | 43,000 |  |  | 43,900 |  |  | 42,200 |
Water distribution connections | 116,200 |  |  | 113,200 |  |  | 115,500 |  |  | 112,800 |
Total Average Active Connections For The Period | 160,600 |  |  | 156,200 |  |  | 159,400 |  |  | 155,000 |
Gallons Provided |  |  |  |  |  |  |
Wastewater treated (millions of gallons) | 592 |  |  | 606 |  |  | 2,338 |  |  | 2,282 |
Water provided (millions of gallons) | 3,868 |  |  | 3,655 |  |  | 15,204 |  |  | 15,823 |
Total Gallons Provided | 4,460 |  |  | 4,261 |  |  | 17,542 |  |  | 18,105 |

During the three months ended December 31, 2019, the water and wastewater distribution systems provided approximately 3,868 million gallons of water to its customers and treated approximately 592 million gallons of wastewater as compared to 3,655 million gallons of water provided and 606 million gallons of wastewater treated during the same period in 2018.
During the twelve months ended December 31, 2019, the water and wastewater distribution systems provided approximately 15,204 million gallons of water to its customers and treated approximately 2,338 million gallons of wastewater as compared to 15,823 million gallons of water and 2,282 million gallons of wastewater during the same period in 2018.

Management Discussion & Analysis – APUC 2019 Annual Report | 16

2019 Regulated Services Group Operating Results

| Three Months Ended December 31 |  | Twelve Months Ended December 31
| 2019 |  | 2018 |  | 2019 |  | 2018
Revenue |  |  |  |  |  |  |
Utility electricity sales and distribution | $ | 181.9 |  |  | $ | 193.2 |  |  | $ | 784.4 |  |  | $ | 831.2 |
Less: cost of sales – electricity | (59.2 | ) |  | (63.4 | ) |  | (247.4 | ) |  | (265.1 | )
Net Utility Sales - electricity1 | 122.7 |  |  | 129.8 |  |  | 537.0 |  |  | 566.1 |
Utility natural gas sales and distribution | 132.3 |  |  | 117.5 |  |  | 402.6 |  |  | 396.6 |
Less: cost of sales – natural gas | (58.9 | ) |  | (59.0 | ) |  | (170.5 | ) |  | (183.0 | )
Net Utility Sales - natural gas1 | 73.4 |  |  | 58.5 |  |  | 232.1 |  |  | 213.6 |
Utility water distribution & wastewater treatment sales and distribution | 32.0 |  |  | 30.4 |  |  | 130.5 |  |  | 128.4 |
Less: cost of sales – water | (2.2 | ) |  | (2.1 | ) |  | (8.1 | ) |  | (8.8 | )
Net Utility Sales - water distribution & wastewater treatment1 | 29.8 |  |  | 28.3 |  |  | 122.4 |  |  | 119.6 |
Gas transportation | 11.4 |  |  | 10.4 |  |  | 35.1 |  |  | 33.4 |
Other revenue | 7.7 |  |  | 4.9 |  |  | 14.3 |  |  | 11.6 |
Net Utility Sales1 | 245.0 |  |  | 231.9 |  |  | 940.9 |  |  | 944.3 |
Operating expenses | (96.0 | ) |  | (99.0 | ) |  | (396.6 | ) |  | (401.5 | )
Other income | 10.2 |  |  | 1.5 |  |  | 15.3 |  |  | 5.6 |
HLBV2 | 1.3 |  |  | 0.6 |  |  | 5.8 |  |  | 3.2 |
Divisional Operating Profit 1,3 | $ | 160.5 |  |  | $ | 135.0 |  |  | $ | 565.4 |  |  | $ | 551.6 |

1 | See Non-GAAP Financial Measures.
2 | HLBV income represents the value of net tax attributes monetized by the Regulated Services Group in the period at the Luning Solar Facility.
3 | Certain prior year items have been reclassified to conform with current year presentation.

Management Discussion & Analysis – APUC 2019 Annual Report | 17

2019 Fourth Quarter Operating Results
For the three months ended December 31, 2019, the Regulated Services Group reported an operating profit (excluding corporate administration expenses) of $160.5 million as compared to $135.0 million for the comparable period in the prior year.
Highlights of the changes are summarized in the following table:

(all dollar amounts in $ millions) | Three Months Ended December 31
Prior Period Operating Profit | $ | 135.0 |
Existing Facilities |
Electricity: Increase is primarily due to operating cost savings at the Granite State Electric System, partially offset by lower consumption due to fewer heating degree days at the Empire Electric System. | 1.2 |
Gas: Increase is primarily due to lower operating costs at the EnergyNorth Gas System as well as additional Gas System Enhancement Program (“GSEP”) recoveries at the New England Gas System. | 2.5 |
Water: Increase is due to higher revenues from organic growth in connections as well as operating cost savings at the Arkansas and Park Water Systems. | 3.1 |
Increase in revenue from utility services provided to Ft. Benning and fees earned from the San Antonio Water System investment. | 7.8 |
Increase in allowance for funds used during construction (“AFUDC”) due to higher construction work in progress. | 3.3 |
| 17.9 |
New Facilities |
Gas: Acquisitions of New Brunswick Gas (October 2019) and St. Lawrence Gas (November 2019). | 7.5 |
| 7.5 |
Rate Reviews |
Electricity: Implementation of new rates at the Granite State Electric System. | 0.3 |
Water: Implementation of lower rates at the Park Water System due to U.S. Tax Reform, partially offset by higher rates at the Tall Timbers Water System, net of U.S. Tax Reform impact. | (0.2 | )
| 0.1 |
Current Period Divisional Operating Profit 1 | $ | 160.5 |

1 | See Non-GAAP Financial Measures.

Management Discussion & Analysis – APUC 2019 Annual Report | 18

2019 Annual Operating Results
For the twelve months ended December 31, 2019, the Regulated Services Group reported an operating profit (excluding corporate administration expenses) of $565.4 million as compared to $551.6 million for the comparable period in the prior year.
Highlights of the changes are summarized in the following table:

(all dollar amounts in $ millions) | Twelve Months Ended December 31
Prior Period Operating Profit | $ | 551.6 |
Existing Facilities |
Electricity: Decrease is primarily due to less extreme weather conditions as compared to the prior year resulting in lower consumption at the Empire Electric System as well as higher operating costs at the CalPeco Electric System, partially offset by operating cost savings at the Granite State and Empire Electric Systems. | (8.8 | )
Gas: Increase is primarily due to operating cost savings at the EnergyNorth, New England and Empire Gas Systems as well as additional GSEP recoveries at the New England Gas System. | 7.5 |
Water: Increase is primarily due to higher revenues resulting from organic growth and several small water utility acquisitions throughout the year in the Arizona, Texas and Park Water Systems as well as operating cost savings at the Park Water and Arkansas Water Systems. | 3.9 |
Increase in revenue from utility services provided to Ft. Benning and fees earned from the San Antonio Water System investment. | 8.1 |
Other: Increase in AFUDC due to higher construction work in progress. | 4.2 |
| 14.9 |
New Facilities |
Gas: Acquisitions of New Brunswick Gas (October 2019) and St. Lawrence Gas (November 2019). | 7.5 |
| 7.5 |
Rate Reviews |
Electricity: Implementation of lower rates at the Empire Electric System due to U.S. Tax Reform. | (13.0 | )
Gas: Implementation of new rates, net of U.S. Tax Reform impact, primarily at the Midstates and EnergyNorth Gas Systems, partially offset by lower rates at the Empire Gas System due to U.S. Tax Reform. | 5.0 |
Water: Implementation of lower rates at the Park Water System due to U.S. Tax Reform, partially offset by new rates, net of U.S. Tax Reform impact, at the Litchfield Park Water System. | (0.6 | )
| (8.6 | )
Current Period Divisional Operating Profit 1 | $ | 565.4 |

1 | See Non-GAAP Financial Measures.

Management Discussion & Analysis – APUC 2019 Annual Report | 19

Regulatory Proceedings
The following table summarizes the major regulatory proceedings currently underway within the Regulated Services Group:

Utility | State/Province | Regulatory Proceeding Type | Rate Request (millions) | Current Status
Completed Rate Reviews |  |  |  |
Peach State Gas System | Georgia | GRAM | $2.7 | On January 31, 2019, an Order was issued approving an increase in revenue of $2.4 million for rates effective February 1, 2019.
New England Gas System | Massachusetts | GSEP | $3.8 | On April 30, 2019, an Order was issued approving an increase in revenue of $2.4 million for rates effective May 1, 2019.
CalPeco Electric System | California | Catastrophic Events Memorandum Account | $3.8 | On June 13, 2019, an Order was issued authorizing a one-time recovery of $3.5 million in revenue associated with its 2017 storm-related costs, effective in rates January 1, 2020.
Empire Electric (Kansas System) | Kansas | GRC | $2.5 | On July 30, 2019, an Order was issued approving base rates to remain unchanged and a transmission delivery charge rider approving an annual increase of $2.5 million. The Order became effective August 1, 2019.
Empire Electric (Oklahoma System) | Oklahoma | GRC | $2.3 | On October 9, 2019, an Order was issued approving an annual base rate increase of $1.4 million effective October 1, 2019.
Various | Various | GRC | $2.4 | Approval of $0.2 million in rate decrease across water, wastewater, and natural gas utilities.
Pending Rate Reviews |  |  |  |
Empire Electric (Missouri System) | Missouri | GRC | $26.5 | On August 14, 2019, filed an application for an annual increase in the revenue requirement of approximately $26.5 million.
Granite State Electric System | New Hampshire | GRC | $9.0 | On April 30, 2019, filed a rate review requesting increases of $2.1 million for temporary rates effective July 1, 2019, $5.7 million for permanent rates effective May 1, 2020, and a step increase of $2.3 million effective May 1, 2020. On June 28, 2019, a temporary rate increase of $2.1 million was approved by the New Hampshire Public Utilities Commission (“NHPUC”). On November 22, 2019, Granite State filed an update requesting an increase of $6.7 million for permanent rates effective May 1, 2020.
Energy North Gas System | New Hampshire | GRC | $13.8 | On November 27, 2019, filed a rate application requesting increases of $7.9 million for temporary rates effective February 1, 2020, $10.8 million for permanent rates effective November 1, 2020, and a step increase of $3.0 million effective November 1, 2020. On January 10, 2020, the NHPUC heard arguments on whether it should use its discretion to not investigate this rate request within a two-year window of time from its prior review. A decision is pending.
New England Gas System | Massachusetts | GSEP | $3.2 | On October 31, 2019, filed the 2020 GSEP application requesting an incremental increase in revenue of $3.2 million effective May 1, 2020.
CalPeco Electric System | California | GRC | $14.9 | A rate review is currently underway requesting a rate increase of $14.9 million over three years ($6.9 million for 2019, $4.1 million for 2020, and $3.9 million for 2021).
Various | Various | Various | $1.9 | Other pending rate review requests across two water utilities and one wastewater utility.

Management Discussion & Analysis – APUC 2019 Annual Report | 20

RENEWABLE ENERGY GROUP

2019 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) |  | 2019 |  | 2018 |  |  | 2019 |  | 2018
Hydro Facilities: |  |  |  |  |  |  |  |  |  |  |
Maritime Region | 37.6 |  |  | 35.8 |  |  | 31.4 |  |  | 148.2 |  |  | 132.7 |  |  | 107.5 |
Quebec Region | 72.6 |  |  | 72.7 |  |  | 73.6 |  |  | 273.3 |  |  | 270.8 |  |  | 263.7 |
Ontario Region | 26.2 |  |  | 22.2 |  |  | 31.3 |  |  | 120.4 |  |  | 103.4 |  |  | 106.5 |
Western Region | 12.6 |  |  | 13.3 |  |  | 11.2 |  |  | 65.0 |  |  | 65.5 |  |  | 59.8 |
| 149.0 |  |  | 144.0 |  |  | 147.5 |  |  | 606.9 |  |  | 572.4 |  |  | 537.5 |
Wind Facilities: |  |  |  |  |  |  |  |  |  |  |
St. Damase | 22.7 |  |  | 20.5 |  |  | 22.2 |  |  | 76.9 |  |  | 76.7 |  |  | 78.8 |
St. Leon | 121.4 |  |  | 112.4 |  |  | 101.4 |  |  | 430.2 |  |  | 404.0 |  |  | 394.8 |
Red Lily1 | 24.1 |  |  | 23.4 |  |  | 20.0 |  |  | 88.5 |  |  | 81.8 |  |  | 81.3 |
Morse | 30.5 |  |  | 25.9 |  |  | 26.2 |  |  | 108.8 |  |  | 96.4 |  |  | 96.8 |
Amherst2 | 67.9 |  |  | 67.0 |  |  | 58.7 |  |  | 229.8 |  |  | 223.4 |  |  | 105.7 |
Sandy Ridge | 43.6 |  |  | 31.9 |  |  | 43.8 |  |  | 158.3 |  |  | 126.5 |  |  | 152.2 |
Minonk | 189.8 |  |  | 193.7 |  |  | 173.8 |  |  | 673.7 |  |  | 654.6 |  |  | 611.3 |
Senate | 140.0 |  |  | 131.1 |  |  | 125.2 |  |  | 520.4 |  |  | 506.0 |  |  | 484.9 |
Shady Oaks | 100.5 |  |  | 97.7 |  |  | 91.5 |  |  | 355.6 |  |  | 345.8 |  |  | 326.6 |
Odell | 238.0 |  |  | 224.9 |  |  | 199.9 |  |  | 831.8 |  |  | 748.1 |  |  | 759.4 |
Deerfield | 167.9 |  |  | 163.9 |  |  | 153.8 |  |  | 546.0 |  |  | 522.6 |  |  | 531.2 |
| 1,146.4 |  |  | 1,092.4 |  |  | 1,016.5 |  |  | 4,020.0 |  |  | 3,785.9 |  |  | 3,623.0 |
Solar Facilities: |  |  |  |  |  |  |  |  |  |  |  |  |  |
Cornwall | 2.2 |  |  | 1.8 |  |  | 1.8 |  |  | 14.7 |  |  | 15.0 |  |  | 14.5 |
Bakersfield | 13.0 |  |  | 12.2 |  |  | 9.5 |  |  | 77.2 |  |  | 68.6 |  |  | 70.0 |
Great Bay Solar3 | 25.7 |  |  | 24.2 |  |  | 26.4 |  |  | 138.5 |  |  | 134.2 |  |  | 110.6 |
| 40.9 |  |  | 38.2 |  |  | 37.7 |  |  | 230.4 |  |  | 217.8 |  |  | 195.1 |
Renewable Energy Performance | 1,336.3 |  |  | 1,274.6 |  |  | 1,201.7 |  |  | 4,857.3 |  |  | 4,576.1 |  |  | 4,355.6 |
Thermal Facilities: |  |  |  |  |  |  |  |  |  |  |  |  |  |
Windsor Locks | N/A 4 |  |  | 28.0 |  |  | 46.1 |  |  | N/A 4 |  |  | 115.3 |  |  | 154.7 |
Sanger | N/A 4 |  |  | 17.8 |  |  | 11.3 |  |  | N/A 4 |  |  | 57.6 |  |  | 146.4 |
|  |  |  | 45.8 |  |  | 57.4 |  |  |  |  |  | 172.9 |  |  | 301.1 |
Total Performance |  |  |  | 1,320.4 |  |  | 1,259.1 |  |  |  |  |  | 4,749.0 |  |  | 4,656.7 |

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 | APUC owns a majority interest in the Amherst Island Wind Facility. The production figures represent full energy produced by the facility. The Amherst Island Wind Facility achieved COD on June 15, 2018 in accordance with the terms of the Power Purchase Agreement (“PPA”), however, the facility was partially operational prior to that date. The twelve months ended December 31, 2018 production data includes all energy produced during the year.
3 | The Great Bay Solar Facility achieved COD on March 29, 2018 in accordance with the terms of the PPA, however, the facility was partially operational prior to that date. The twelve months ended December 31, 2018 production data includes all energy produced during the year.
4 | Natural gas fired co-generation facility.

Management Discussion & Analysis – APUC 2019 Annual Report | 21

2019 Fourth Quarter Renewable Energy Group Performance
For the three months ended December 31, 2019, the Renewable Energy Group generated 1,320.4 GW-hrs of electricity as compared to 1,259.1 GW-hrs during the same period of 2018.
For the three months ended December 31, 2019, the hydro facilities generated 144.0 GW-hrs of electricity as compared to 147.5 GW-hrs produced in the same period in 2018, a decrease of 2.4%. Electricity generated represented 96.6% of long-term average resources (“LTAR”) as compared to 99.0% during the same period in 2018. During the quarter, all regions except the Maritime Region were above their respective LTAR.
For the three months ended December 31, 2019, the wind facilities produced 1,092.4 GW-hrs of electricity as compared to 1,016.5 GW-hrs produced in the same period in 2018, an increase of 7.5%. During the three months ended December 31, 2019, the wind facilities generated electricity equal to 95.3% of LTAR as compared to 88.7% during the same period in 2018.
For the three months ended December 31, 2019, the solar facilities generated 38.2 GW-hrs of electricity as compared to 37.7 GW-hrs of electricity in the same period in 2018, an increase of 1.3%. The solar facilities generated electricity equal to 93.4% of LTAR as compared to 92.2% in the same period in 2018.
For the three months ended December 31, 2019, the thermal facilities generated 45.8 GW-hrs of electricity as compared to 57.4 GW-hrs of electricity during the same period in 2018. During the same period, the Windsor Locks Thermal Facility generated 153.7 billion lbs of steam as compared to 145.7 billion lbs of steam during the same period in 2018.
2019 Annual Renewable Energy Group Performance
For the twelve months ended December 31, 2019, the Renewable Energy Group generated 4,749.0 GW-hrs of electricity as compared to 4,656.7 GW-hrs during the same period of 2018.
For the twelve months ended December 31, 2019, the hydro facilities generated 572.4 GW-hrs of electricity as compared to 537.5 GW-hrs produced in the same period in 2018, an increase of 6.5%. Electricity generated represented 94.3% of LTAR as compared to 88.6% during the same period in 2018.
For the twelve months ended December 31, 2019, the wind facilities produced 3,785.9 GW-hrs of electricity as compared to 3,623.0 GW-hrs produced in the same period in 2018, an increase of 4.5%. The increase in production was primarily due to incremental electricity generated at the Amherst Wind Facility which achieved COD on June 15, 2018. During the twelve months ended December 31, 2019, the wind facilities generated electricity equal to 94.2% of LTAR as compared to 92.7% during the same period in 2018.
For the twelve months ended December 31, 2019, the solar facilities generated 217.8 GW-hrs of electricity as compared to 195.1 GW-hrs of electricity produced in the same period in 2018, an increase of 11.6%. The increase in production is primarily due to the addition of the Great Bay Solar Facility which achieved full COD on March 29, 2018. The solar facilities generated electricity equal to 94.5% of LTAR as compared to 94.0% in the same period in 2018.
For the twelve months ended December 31, 2019, the thermal facilities generated 172.9 GW-hrs of electricity as compared to 301.1 GW-hrs of electricity during the same period in 2018. During the same period, the Windsor Locks Thermal Facility generated 555.4 billion lbs of steam as compared to 566.9 billion lbs of steam during the same period in 2018.

Management Discussion & Analysis – APUC 2019 Annual Report | 22

2019 Renewable Energy Group Operating Results
| Three Months Ended December 31 |  | Twelve Months Ended December 31
(all dollar amounts in $ millions) | 2019 |  | 2018 |  | 2019 |  | 2018
Revenue1 |  |  |  |  |  |  |
Hydro | $ | 10.4 |  |  | $ | 11.7 |  |  | $ | 41.7 |  |  | $ | 42.6 |
Wind | 49.4 |  |  | 37.7 |  |  | 153.3 |  |  | 133.5 |
Solar | 2.8 |  |  | 2.8 |  |  | 18.6 |  |  | 17.2 |
Thermal | 8.1 |  |  | 10.2 |  |  | 32.9 |  |  | 42.1 |
Total Revenue | $ | 70.7 |  |  | $ | 62.4 |  |  | $ | 246.5 |  |  | $ | 235.4 |
Less: |  |  |  |  |  |  |
Cost of Sales - Energy2 | (0.9 | ) |  | (1.4 | ) |  | (4.3 | ) |  | (5.5 | )
Cost of Sales - Thermal | (3.2 | ) |  | (5.1 | ) |  | (13.0 | ) |  | (21.7 | )
Realized gain/(loss) on hedges3 | — |  |  | 0.1 |  |  | (0.2 | ) |  | 0.1 |
Net Energy Sales 8 | $ | 66.6 |  |  | $ | 56.0 |  |  | $ | 229.0 |  |  | $ | 208.3 |
Renewable Energy Credits4 | 2.8 |  |  | 2.7 |  |  | 10.1 |  |  | 11.0 |
Other Revenue | 0.8 |  |  | 0.4 |  |  | 1.4 |  |  | 0.9 |
Total Net Revenue | $ | 70.2 |  |  | $ | 59.1 |  |  | $ | 240.5 |  |  | $ | 220.2 |
Expenses & Other Income |  |  |  |  |  |  |
Operating expenses | (19.2 | ) |  | (13.2 | ) |  | (75.2 | ) |  | (71.0 | )
Dividend, interest, equity and other income5 | 20.2 |  |  | 18.3 |  |  | 104.0 |  |  | 45.7 |
HLBV income8 | 14.7 |  |  | 14.5 |  |  | 59.2 |  |  | 108.7 |
Divisional Operating Profit 6,7 | $ | 85.9 |  |  | $ | 78.7 |  |  | $ | 328.5 |  |  | $ | 303.6 |

1 | Many of the Renewable Energy Group’s PPAs include annual rate increases however, a change to the weighted average production levels resulting from higher average production from facilities that earn lower energy rates can result in a lower weighted average energy rate earned by the division as compared to the same period in the prior year.
2 | Cost of Sales - Energy consists of energy purchases in the Maritime Region to manage the energy sales from the Tinker Hydro Facility which is sold to retail and industrial customers under multi-year contracts.
3 | See Note 24(b)(iv) in the annual audited consolidated financial statements.
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-hr of electricity was generated from an eligible energy source.
5 | Includes dividends received from Atlantica and related parties (see Note 8 and 16 in the annual audited consolidated financial statements).
6 | Certain prior year items have been reclassified to conform to current year presentation.
7 | See Non-GAAP Financial Measures.

8 HLBV Income and Production Tax Credits
HLBV income represents the value of net tax attributes earned by the Renewable Energy Group in the period primarily from electricity generated by certain of its U.S. wind and U.S. solar generation facilities.
Production Tax Credits (“PTCs”) are earned as wind energy is generated based on a dollar per kW-hr rate prescribed in applicable federal and state statutes. For the three and twelve months ended December 31, 2019, the Renewable Energy Group’s eligible facilities generated 745.5 and 2,557.8 GW-hrs representing approximately $18.6 million and $63.9 million in PTCs earned as compared to 696.5 and 2,539.0 GW-hrs representing $16.7 million and $60.9 million in PTCs earned during the same period in 2018. The majority of the PTCs have been allocated to tax equity investors to monetize the value to APUC of the PTCs and other tax attributes which are being recognized as HLBV income.

Management Discussion & Analysis – APUC 2019 Annual Report | 23

2019 Fourth Quarter Operating Results
For the three months ended December 31, 2019, the Renewable Energy Group’s facilities generated $85.9 million of operating profit as compared to $78.7 million during the same period in 2018, which represents an increase of $7.2 million or 9.1%, 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 | $ | 78.7 |
Existing Facilities |
Hydro: Decrease is primarily due to lower production in the Ontario and Quebec Regions, partially offset by additional REC revenue and lower operating expenses. | (0.2 | )
Wind Canada: Increase is primarily due to higher production at the St. Leon Wind Facility, partially offset by higher operating expenses. | 0.9 |
Wind U.S.: Increase is primarily due to higher overall production as well as lower operating expenses. | 2.4 |
Solar Canada | — |
Solar U.S.: Decrease due to lower production at the Great Bay Solar Facility partially offset by favorable REC pricing, higher HLBV income and higher production at the Bakersfield Solar Facility. | (0.2 | )
Thermal: Increase is primarily due to lower cost of fuel at the Sanger Thermal Facility as well additional REC revenue, partially offset by lower production at the Windsor Locks Thermal Facility. | 0.4 |
Other: Decrease is due to higher expenses related to early stage development projects. | (1.7 | )
| 1.6 |
New Facilities and Investments |
Wind Canada: The Amherst Island Wind Facility was previously accounted for as an equity investment. | 4.5 |
Atlantica & AAGES: Dividends from Atlantica1, net of AAGES equity loss. | 1.0 |
| 5.5 |
Foreign Exchange | 0.1 |
Current Period Divisional Operating Profit 2 | $ | 85.9 |

1 | Includes dividends received from Atlantica and related parties (see Note 8 and 16 in the annual audited consolidated financial statements).
2 | See Non-GAAP Financial Measures.

Management Discussion & Analysis – APUC 2019 Annual Report | 24

2019 Annual Operating Results
For the twelve months ended December 31, 2019, the Renewable Energy Group’s facilities generated $328.5 million of operating profit as compared to $303.6 million during the same period in 2018, which represents an increase of $24.9 million or 8.2%, 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 | $ | 303.6 |
Existing Facilities |
Hydro: Increase is primarily due to higher production and additional REC sales, partially offset by higher operating expenses. | 0.8 |
Wind Canada: Increase is primarily due to annual rate increases and higher production at the St. Leon Wind Facility, partially offset by higher operating costs. | 1.6 |
Wind U.S.: Decrease is primarily due to HLBV income acceleration ($54.9 million) resulting from U.S. Tax Reform recognized in the prior year, lower market pricing at the Senate Wind Facility and lower REC rates at the Minonk Wind Facility, partially offset by higher overall production. | (54.2 | )
Solar Canada: Decrease is primarily due to higher operating expenses offset by higher production. | (0.1 | )
Solar U.S.: Decrease is primarily due to HLBV income acceleration ($1.0 million) resulting from U.S. Tax Reform that was recognized in the prior year. | (1.0 | )
Thermal: Increase is primarily due to lower operating costs, lower cost of fuel and higher REC revenue, partially offset by lower overall production. | 0.7 |
Other: Increase is due to lower expenses related to early stage development projects. | 3.1 |
| (49.1 | )
New Facilities and Investments |
Wind Canada: Amherst Island Wind Facility achieved COD in June 2018. | 15.9 |
Solar U.S.: Great Bay Solar Facility achieved full COD in March 2018. | 6.4 |
Atlantica and AAGES: Dividends from Atlantica1 net of AAGES equity loss. | 53.0 |
| 75.3 |
Foreign Exchange | (1.3 | )
Current Period Divisional Operating Profit 2 | $ | 328.5 |

1 | Includes dividends received from Atlantica and related parties (see Note 8 and 16 in the annual audited consolidated financial statements).
2 | See Non-GAAP Financial Measures.

Management Discussion & Analysis – APUC 2019 Annual Report | 25

APUC: CORPORATE AND OTHER EXPENSES

| Three Months Ended December 31 |  | Twelve Months Ended December 31
(all dollar amounts in $ millions) | 2019 |  | 2018 |  | 2019 |  | 2018
Corporate and other expenses: |  |  |  |  |  |  |
Administrative expenses | $ | 15.2 |  |  | $ | 15.0 |  |  | $ | 56.8 |  |  | $ | 52.7 |
Loss (gain) on foreign exchange | 3.1 |  |  | 0.7 |  |  | 3.1 |  |  | (0.1 | )
Interest expense | 47.4 |  |  | 40.3 |  |  | 181.5 |  |  | 152.1 |
Depreciation and amortization | 77.7 |  |  | 63.8 |  |  | 284.3 |  |  | 260.8 |
Change in value of investments carried at fair value | (98.1 | ) |  | 46.0 |  |  | (278.1 | ) |  | 138.0 |
Interest, dividend, equity, and other (income) loss1 | (0.4 | ) |  | (0.4 | ) |  | (1.6 | ) |  | (1.8 | )
Pension and post-employment non-service costs | 8.4 |  |  | 3.4 |  |  | 17.3 |  |  | 5.0 |
Other losses | 6.2 |  |  | 2.3 |  |  | 15.1 |  |  | 2.7 |
Acquisition-related costs, net | 6.4 |  |  | (8.9 | ) |  | 11.6 |  |  | 0.7 |
Loss (gain) on derivative financial instruments | (0.5 | ) |  | (0.3 | ) |  | (16.1 | ) |  | 0.6 |
Income tax expense | 12.5 |  |  | 2.8 |  |  | 70.1 |  |  | 53.4 |

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

2019 Fourth Quarter Corporate and Other Expenses
During the three months ended December 31, 2019, administrative expenses totaled $15.2 million as compared to $15.0 million in the same period in 2018.
For the three months ended December 31, 2019, interest expense totaled $47.4 million as compared to $40.3 million in the same period in 2018. The increase was primarily due to the issuance of senior unsecured debentures and the Notes in January and May of 2019 respectively.
For the three months ended December 31, 2019, depreciation expense totaled $77.7 million as compared to $63.8 million in the same period in 2018. The increase is primarily due to higher overall property, plant and equipment.
For the three months ended December 31, 2019, change in investments carried at fair value totaled a gain of $98.1 million as compared to a loss of $46 million in 2018. The Company records certain of its investments, including Atlantica, using the fair value method and accordingly any change in the fair value of the investment is recorded in the Statement of Operations (see Note 8 in the annual audited consolidated financial statements).
For the three months ended December 31, 2019, pension and post-employment non-service costs totaled $8.4 million as compared to $3.4 million in 2018. The increase in 2019 was primarily due to the actual return on plan assets in 2018 being lower than anticipated, resulting in lower expected return on assets in 2019 and higher amortization cost of actuarial losses.
For the three months ended December 31, 2019, other losses were $6.2 million as compared to $2.3 million in the same period in 2018. The loss in 2019 was primarily related to condemnation costs for Liberty Utilities (Apple Valley Ranchos Water) Corp. as well as write-downs of some regulatory assets at the Empire Electric and Energy North Natural Gas Systems. The loss in 2018 primarily related to the write down of notes receivables and costs from condemnation proceedings.
For the three months ended December 31, 2019, acquisition related costs totaled $6.4 million as compared to a cost recovery of $8.9 million in 2018. The expense in 2019 was primarily related to the investment in Atlantica, the pending acquisition of New York American Water and the acquisitions of New Brunswick Gas and St. Lawrence Gas. The recovery in 2018 was primarily due to a settlement related to the Shady Oaks Wind Facility acquisition.
For the three months ended December 31, 2019, gain on derivative financial instruments totaled $0.5 million as compared to $0.3 million in the same period in 2018. The gains in 2019 were primarily driven by mark-to-market gains on energy derivatives.
For the three months ended December 31, 2019, an income tax expense of $12.5 million was recorded as compared to an income tax expense of $2.8 million during the same period in 2018. In the three months ended December 31, 2019, increases to income tax expense are primarily due to the change in fair value associated with the investment in Atlantica partially offset by lower income subject to tax and investment tax credits earned. In the three months ended December 31, 2018, income tax expense was impacted by a one-time U.S. Tax Reform related benefit.

Management Discussion & Analysis – APUC 2019 Annual Report | 26

2019 Annual Corporate and Other Expenses
During the twelve months ended December 31, 2019, administrative expenses totaled $56.8 million as compared to $52.7 million in the same period in 2018. The increase primarily relates to additional costs incurred to administer APUC’s operations as a result of the Company’s growth.
For the twelve months ended December 31, 2019, interest expense totaled $181.5 million as compared to $152.1 million in the same period in 2018. The increase was primarily due to the issuance of subordinated notes in October 2018 and May 2019 and higher average long-term debt balances.
For the twelve months ended December 31, 2019, depreciation expense totaled $284.3 million as compared to $260.8 million in the same period in 2018. The increase is primarily due to higher overall property, plant and equipment.
For the twelve months ended December 31, 2019, change in investments carried at fair value totaled a gain of $278.1 million as compared to a loss of $138.0 million in the same period in 2018. The Company records certain of its investments, including Atlantica, using the fair value method and accordingly any change in the fair value of the investment is recorded in the Statement of Operations (see Note 8 in the annual audited consolidated financial statements).
For the twelve months ended December 31, 2019, pension and post-employment non-service costs totaled $17.3 million as compared to $5.0 million in the same period in 2018. The increase in 2019 was primarily due to the actual return on plan assets in 2018 being lower than expected, resulting in lower expected return on assets in 2019 and higher amortization cost of actuarial losses.
For the twelve months ended December 31, 2019, other losses were $15.1 million as compared to $2.7 million in the same period in 2018. The loss in 2019 is primarily related to condemnation costs for Liberty Utilities (Apple Valley Ranchos Water) Corp. as well as write-downs of regulatory assets at the Empire Electric, Energy North Natural Gas and Granite State Electric Systems. The loss in 2018 was primarily related to the write-down of notes receivables and costs from condemnation proceedings.
For the twelve months ended December 31, 2019, acquisition-related costs totaled $11.6 million as compared to $0.7 million in the same period in 2018. The expense in 2019 was primarily related to the investment in Atlantica, the pending acquisition of New York American Water and the acquisitions of New Brunswick Gas and St. Lawrence Gas. The costs in 2018 primarily related to the investment in Atlantica, partially offset by a settlement related to the Shady Oaks Wind Facility acquisition.
For the twelve months ended December 31, 2019, the gain on derivative financial instruments totaled $16.1 million as compared to a loss of $0.6 million in the same period in 2018. The gain in 2019 was primarily related to the discontinuation of hedge accounting on energy derivatives as a result of the sale of an interest in the Sugar Creek Wind Project to AAGES (see Note 24(b)(ii) in the annual audited consolidated financial statements).
An income tax expense of $70.1 million was recorded in the twelve months ended December 31, 2019 as compared to an income tax expense of $53.4 million during the same period in 2018. In 2019, increases to income tax expense are primarily due to the change in fair value associated with the investment in Atlantica partially offset by lower income subject to tax and investment tax credits earned. In 2018, income tax expense was impacted by a one-time U.S. Tax Reform related benefit offset by higher HLBV earnings in 2018 also due to U.S. Tax Reform.

Management Discussion & Analysis – APUC 2019 Annual Report | 27

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) | 2019 |  | 2018 |  | 2019 |  | 2018
Net earnings attributable to shareholders | $ | 172.1 |  |  | $ | 44.0 |  |  | $ | 530.9 |  |  | $ | 185.0 |
Add (deduct): |  |  |  |  |  |  |
Net earnings attributable to the non-controlling interest, exclusive of HLBV1 | (3.7 | ) |  | 3.4 |  |  | 19.1 |  |  | 4.8 |
Income tax expense | 12.5 |  |  | 2.8 |  |  | 70.1 |  |  | 53.4 |
Interest expense on long-term debt and others | 47.4 |  |  | 40.3 |  |  | 181.5 |  |  | 152.1 |
Other losses | 6.2 |  |  | 2.3 |  |  | 15.1 |  |  | 2.7 |
Acquisition-related costs | 6.4 |  |  | (8.9 | ) |  | 11.6 |  |  | 0.7 |
Pension and post-employment non-service costs | 8.4 |  |  | 3.4 |  |  | 17.3 |  |  | 5.0 |
Change in value of investments carried at fair value2 | (98.1 | ) |  | 46.0 |  |  | (278.1 | ) |  | 138.0 |
Costs related to tax equity financing | — |  |  | 1.3 |  |  | — |  |  | 1.3 |
Loss (gain) on derivative financial instruments | (0.5 | ) |  | (0.3 | ) |  | (16.1 | ) |  | 0.6 |
Realized (loss) gain on energy derivative contracts | — |  |  | 0.1 |  |  | (0.2 | ) |  | 0.1 |
Loss (gain) on foreign exchange | 3.1 |  |  | 0.7 |  |  | 3.1 |  |  | (0.1 | )
Depreciation and amortization | 77.7 |  |  | 63.8 |  |  | 284.3 |  |  | 260.8 |
Adjusted EBITDA | $ | 231.5 |  |  | $ | 198.9 |  |  | $ | 838.6 |  |  | $ | 804.4 |

1 |  | 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, 2019 amounted to $16.0 million and $65.0 million as compared to $13.8 million and $110.7 million during the same period in 2018. In the first quarter of 2018 a one-time acceleration of HLBV income in the amount of $55.9 million was recorded as a result of U.S. Tax Reform. Excluding the one-time acceleration of HLBV due to U.S. Tax Reform, Adjusted EBITDA increased by $90.1 million year over year.
2 |  | See Note 8 in the annual audited consolidated financial statements

Management Discussion & Analysis – APUC 2019 Annual Report | 28

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 except per share information) | 2019 |  | 2018 |  | 2019 |  | 2018
Net earnings attributable to shareholders | $ | 172.1 |  |  | $ | 44.0 |  |  | $ | 530.9 |  |  | $ | 185.0 |
Add (deduct): |  |  |  |  |  |  |
Loss (gain) on derivative financial instruments1 | (0.5 | ) |  | (0.3 | ) |  | (0.3 | ) |  | 0.6 |
Realized (loss) gain on energy derivative contracts | — |  |  | 0.1 |  |  | (0.2 | ) |  | 0.1 |
Other losses | 6.1 |  |  | 1.9 |  |  | 15.1 |  |  | 0.8 |
Loss (gain) on foreign exchange | 3.0 |  |  | 0.7 |  |  | 3.1 |  |  | (0.1 | )
Acquisition-related costs | 6.4 |  |  | (8.9 | ) |  | 11.6 |  |  | 0.7 |
Change in value of investments carried at fair value3 | (98.1 | ) |  | 46.0 |  |  | (278.1 | ) |  | 138.0 |
Costs related to tax equity financing | — |  |  | 1.3 |  |  | — |  |  | 1.3 |
Other non-recurring adjustments | 2.2 |  |  | — |  |  | 2.2 |  |  | — |
U.S. Tax Reform and related deferred tax adjustments2 | — |  |  | (18.4 | ) |  | — |  |  | (18.4 | )
Adjustment for taxes related to above | 12.4 |  |  | 4.1 |  |  | 37.0 |  |  | 4.2 |
Adjusted Net Earnings | $ | 103.6 |  |  | $ | 70.5 |  |  | $ | 321.3 |  |  | $ | 312.2 |
Adjusted Net Earnings per share | $ | 0.20 |  |  | $ | 0.14 |  |  | $ | 0.63 |  |  | $ | 0.66 |

1 | Excludes the gain related to the discontinuation of hedge accounting on an energy hedge put in place early in the development of the Sugar Creek Wind Project (See Note 24(b)(ii) in the annual audited consolidated financial statements).
2 | Represents the non-cash accounting adjustment related to the revaluation of U.S. deferred income tax assets and liabilities as a result of implementation of the effects of U.S. Tax Reform.
3 | See Note 8 in the annual audited consolidated financial statements

For the three months ended December 31, 2019, Adjusted Net Earnings totaled $103.6 million as compared to Adjusted Net Earnings of $70.5 million for the same period in 2018, an increase of $33.1 million.
For the twelve months ended December 31, 2019, Adjusted Net Earnings totaled $321.3 million as compared to Adjusted Net Earnings of $312.2 million for the same period in 2018, an increase of $9.1 million. In the first quarter of 2018 a one-time acceleration of HLBV income in the amount of $55.9 million was recorded as a result of U.S. Tax Reform.

Management Discussion & Analysis – APUC 2019 Annual Report | 29

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) | 2019 |  | 2018 |  | 2019 |  | 2018
Cash flows from operating activities | $ | 167.5 |  |  | $ | 168.6 |  |  | $ | 611.3 |  |  | $ | 530.4 |
Add (deduct): |  |  |  |  |  |  |
Changes in non-cash operating items | (29.8 | ) |  | (27.3 | ) |  | (60.3 | ) |  | 8.1 |
Production based cash contributions from non-controlling interests | — |  |  | — |  |  | 3.6 |  |  | 13.9 |
Acquisition-related costs | 6.4 |  |  | (8.8 | ) |  | 11.6 |  |  | 0.7 |
Reimbursement of operating expenses incurred on joint venture | — |  |  | — |  |  | — |  |  | 1.0 |
Adjusted Funds from Operations | $ | 144.1 |  |  | $ | 132.5 |  |  | $ | 566.2 |  |  | $ | 554.1 |

For the three months ended December 31, 2019, Adjusted Funds from Operations totaled $144.1 million as compared to Adjusted Funds from Operations of $132.5 million for the same period in 2018, an increase of $11.6 million.
For the twelve months ended December 31, 2019, Adjusted Funds from Operations totaled $566.2 million as compared to Adjusted Funds from Operations of $554.1 million for the same period in 2018, an increase of $12.1 million. The increase is primarily due to an increase in earnings from operating facilities and an increase in income from long-term investments.

Management Discussion & Analysis – APUC 2019 Annual Report | 30

CORPORATE DEVELOPMENT ACTIVITIES
The Company undertakes development activities working within a global reach to identify, develop, and construct both regulated and non-regulated renewable power generating facilities, power transmission lines, water infrastructure assets, and other complementary infrastructure projects as well as to invest in local utility electric, natural gas and water distribution systems.
The Company has identified an approximately $9.2 billion development pipeline consisting of approximately $6.7 billion of investments in its Regulated Services Group and approximately $2.5 billion of investments in its Renewable Energy Group through the end of 2024.
APUC pursues investment opportunities with an objective to maintain its business mix in approximately the same proportion as currently exists between its Regulated Services Group and Renewable Energy Group and within credit metrics expected to maintain its current credit ratings. The business mix target may from time to time require APUC to grow its Regulated Services Group or implement other strategies in order to pursue investment opportunities within its Renewable Energy Group.
Development of Regulated Services Assets
The approximately five-year $6.7 billion Regulated Services Group pipeline consists of investments of $2.7 billion in organic rate base capital expenditures, $1.1 billion in capital expenditures related to improving the quality of choice and efficiency of service provided to our customers, $1.1 billion on pending acquisitions, and $1.9 billion in initiatives focused on transition to green energy (“Greening the Fleet”).
Organic rate base capital expenditures are primarily related to the maintenance and expansion of existing rate base assets, including: the construction of transmission and distribution main replacements, work on new and existing substation assets and initiatives relating to the safety and reliability of the electric and gas systems.
Capital expenditures related to improving quality and efficiency of service to our customers include the implementation of new customer information systems, advanced metering systems and behind the meter solutions.
Pending acquisitions include BELCO for approximately $0.5 billion, which is expected to close later in 2020, and New York American Water for approximately $0.6 billion, which is expected to close sometime in 2021.
The $1.9 billion Greening the Fleet initiatives consist primarily of a $1.1 billion Mid-West Wind Development project (described below) and $0.8 billion in other initiatives related to the transition to renewable energy generation at our existing regulated facilities, including transitioning of the CalPeco Electric System to 100% renewable energy and, following the anticipated closing of the acquisition of Ascendant, reducing the reliance on diesel generation at BELCO, replacing it with a combination of renewable energy generation and storage while reducing the cost of electricity to BELCO customers.
Mid-West Wind Development Project
In 2017, the Regulated Services Group presented a plan to the necessary public utility commissions for an investment in up to 600 MW of strategically located wind energy generation which is forecast to reduce energy costs for its customers. The plan consists of development of an approximately 300 MW wind project in southeastern Kansas, and two approximately 150 MW wind projects in southwestern Missouri.
On May 9, 2019, the Arkansas Public Service Commission issued its order allowing the commencement of construction of the projects. In the fourth quarter of 2018, Empire District Electric Company (“Empire”) applied to the Missouri Public Service Commission for approval of certificates of CC&N for the projects. The Commission issued an order approving the CC&N application, effective June 29, 2019.
Liberty Utilities Co. has acquired an interest in the entities that own the two Missouri projects and, in partnership with a third-party developer, will continue development and construction of the two Missouri projects. A second third party developer is developing the wind project in Kansas. Empire has entered into contracts to acquire the three wind projects upon completion.
Construction of two of the wind farms began in the fourth quarter of 2019 and construction on the third wind farm began in the first quarter of 2020.

Management Discussion & Analysis – APUC 2019 Annual Report | 31

Development of Renewable Energy Assets
The Renewable Energy Group has successfully advanced a number of projects and has been awarded or acquired a number of PPAs and/or long-term hedging arrangements. The projects identified are at various stages of development, and have advanced to a stage where the resolutions to major project uncertainties are probable, but not certain, and it is expected that the project will meet management’s risk adjusted return expectations.
The Renewable Energy Group’s five-year $2.5 billion pipeline consists of investments in renewable generation projects in North America and indirect international investments. The following table represents the Renewable Energy Group’s development and construction projects:

Project Name | Location | Anticipated Size (MW)
Projects in Construction |  |
Altavista Solar Project1,2 | Virginia | 80
Great Bay II Solar Project | Maryland | 45
Maverick Creek Wind Project1 | Texas | 490
Sugar Creek Wind Project1 | Illinois | 202
Val-Eo Phase I Wind Project1 | Quebec | 24
Total Projects in Construction |  | 841
Total Projects in Development |  | 600
Total Projects in Construction and Development |  | 1,441

1 | The project is currently held in a joint venture, of which the Renewable Energy Group and a third party each own a 50% equity interest.
2 | Power from the project will be sold, in part, to Facebook Operations, LLC, a wholly-owned subsidiary of Facebook, Inc., pursuant to a 12-year PPA.

SUMMARY OF PROPERTY, PLANT, AND EQUIPMENT EXPENDITURES

| Three Months Ended December 31 |  | Twelve Months Ended December 31
(all dollar amounts in $ millions) | 2019 |  | 2018 |  | 2019 |  | 2018
Regulated Services Group |  |  |  |  |  |  |
Rate Base Maintenance | $ | 51.9 |  |  | $ | 41.5 |  |  | $ | 194.5 |  |  | $ | 177.7 |
Rate Base Growth | 185.1 |  |  | 76.0 |  |  | 373.5 |  |  | 173.9 |
Property, Plant & Equipment Acquired1 | 186.2 |  |  | — |  |  | 186.6 |  |  | — |
| $ | 423.2 |  |  | $ | 117.5 |  |  | $ | 754.6 |  |  | $ | 351.6 |
Renewable Energy Group |  |  |  |  |  |  |
Maintenance | $ | 12.5 |  |  | $ | 12.6 |  |  | $ | 37.3 |  |  | $ | 27.4 |
Investment in Capital Projects2 | (47.1 | ) |  | (18.0 | ) |  | 425.8 |  |  | 71.6 |
International Investments3 | 28.0 |  |  | 345.0 |  |  | 122.2 |  |  | 957.6 |
| $ | (6.6 | ) |  | $ | 339.6 |  |  | $ | 585.3 |  |  | $ | 1,056.6 |
Total Capital Expenditures | $ | 416.6 |  |  | $ | 457.1 |  |  | $ | 1,339.9 |  |  | $ | 1,408.2 |

1 | Property, Plant & Equipment acquired through acquisitions of New Brunswick Gas and St. Lawrence Gas.
2 | Includes expenditures on Property Plant & Equipment, equity-method investees, and acquisitions of operating entities that may have been jointly developed by the Company with another third party developer.
3 | Investments in Atlantica are reflected at historical investment cost and not fair value.

Management Discussion & Analysis – APUC 2019 Annual Report | 32

2019 Fourth Quarter Property Plant and Equipment Expenditures
During the three months ended December 31, 2019, the Regulated Services Group invested $423.2 million ($237.0 million excluding acquisitions) in capital expenditures as compared to $117.5 million during the same period in 2018. The Regulated Services Group’s investment was primarily related to the construction of transmission and distribution main replacements, work on new and existing substation assets, initiatives relating to the safety and reliability of the electric and gas systems. The acquisitions of New Brunswick Gas and St. Lawrence Gas added $186.2 million of property, plant and equipment.
The Renewable Energy Group’s investment during the quarter was primarily to fund the Altavista and Great Bay II Solar Projects as well as ongoing maintenance capital at existing operating sites. During the quarter, the Maverick Creek and Sugar Creek Wind Joint Ventures reimbursed the Company for funds previously advanced. As a result, the Renewable Energy Group recorded a net reimbursement of $6.6 million during the quarter as compared to capital expenditures of $339.6 million during the same period in 2018.
2019 Annual Property Plant and Equipment Expenditures
During the twelve months ended December 31, 2019, the Regulated Services Group invested $754.6 million in capital expenditures as compared to $351.6 million during the same period in 2018. The Regulated Services Group’s investment was primarily related to the construction of transmission and distribution main replacements, the completion and start of work on new and existing substation assets, initiatives relating to the safety and reliability of the electric and gas systems, and investment in the Wataynikaneyap Power Transmission Project. The acquisitions of New Brunswick Gas and St. Lawrence Gas added $186.2 million of property, plant and equipment.
During the twelve months ended December 31, 2019, the Renewable Energy Group incurred capital expenditures of $585.3 million as compared to $1,056.6 million during the same period in 2018. The Renewable Energy Group’s investment was primarily related to the purchase of the remaining 50% interest in the Amherst Island Wind Facility from its joint venture partner, development costs for the Altavista and Great Bay II Solar Projects, and Sugar Creek Wind Project, investment in the Vista Ridge Water Pipeline Project, investments into Atlantica; as well as ongoing sustaining capital at existing operating sites.
2020 Capital Investments
Over the course of the 2020 financial year, the Company expects to spend between $1.60 billion - $1.85 billion on capital investment opportunities. Actual expenditures in 2020 may vary due to timing of various project investments and the realized Canadian to U.S. dollar exchange rate.
Ranges of expected capital investment in the 2020 financial year are as follows:

(all dollar amounts in $ millions) |  |  |
Regulated Services Group: |  |  |
Rate Base Maintenance | $ | 200.0 |  | - | $ | 250.0 |
Rate Base Growth | 450.0 |  | - | 500.0 |
Rate Base Acquisitions1 | 500.0 |  | - | 550.0 |
Total Regulated Services Group: | $ | 1,150.0 |  | - | $ | 1,300.0 |
Renewable Energy Group: |  |  |
Maintenance | $ | 25.0 |  | - | $ | 50.0 |
Investment in Capital Projects | 375.0 |  | - | 425.0 |
International Investments | 50.0 |  | - | 75.0 |
Total Renewable Energy Group: | $ | 450.0 |  | - | $ | 550.0 |
Total 2020 Capital Investments | $ | 1,600.0 |  | - | $ | 1,850.0 |

1 | Includes international investments in utilities.

The Regulated Services Group expects to spend between $1,150.0 million - $1,300.0 million over the course of 2020 in an effort to expand our operations, improve the reliability of the utility systems and broaden the technologies used to better serve its service areas. Project spending includes capital for structural improvements, specifically in relation to refurbishing substations, replacing poles and wires, drilling and equipping aquifers, main replacements, and reservoir pumping stations. The Regulated Services Group expects to close the acquisitions of BELCO and the Perris Water Distribution Company in 2020.
The Company expects to fund its 2020 capital plan through a combination of retained cash, tax equity funding, senior debentures, bank revolving and term credit facilities, and common equity and equity like instruments.

Management Discussion & Analysis – APUC 2019 Annual Report | 33

The Renewable Energy Group intends to spend between $450.0 million - $550.0 million over the course of 2020 to develop or further invest in capital projects, primarily in relation to: (i) development of the Maverick Creek, Sugar Creek, Shady Oaks II and Blue Hill Wind Projects as well as the Altavista and Great Bay II Solar Projects, and (ii) additional international investments. Furthermore, the Renewable Energy Group plans to spend $25.0 million - $50.0 million on various operational solar, thermal, and wind assets to maintain safety, regulatory, and operational efficiencies.
LIQUIDITY AND CAPITAL RESERVES
APUC has revolving credit and letter of credit facilities as well as separate credit facilities for the Regulated Services Group, and the Renewable Energy Group to manage the liquidity and working capital requirements of each division (collectively the “Bank Credit Facilities”).
Bank Credit Facilities
The following table sets out the Bank Credit Facilities available to APUC and its operating groups as at December 31, 2019:

| As at December 31, 2019 |  | As at Dec 31, 2018
(all dollar amounts in $ millions) | Corporate |  | Regulated Services Group |  | Renewable Energy Group |  | Total |  | Total
Credit facilities | $ | 575.0 |  | 1 | $ | 500.0 |  |  | $ | 700.0 |  | 2 | $ | 1,775.0 |  |  | $ | 1,321.0 |
Funds drawn on facilities/ Commercial paper issued | (143.0 | ) |  | (218.0 | ) |  | — |  |  | (361.0 | ) |  | (103.0 | )
Letters of credit issued | (37.3 | ) |  | (48.2 | ) |  | (131.3 | ) |  | (216.8 | ) |  | (171.1 | )
Liquidity available under the facilities | 394.7 |  |  | 233.8 |  |  | 568.7 |  |  | 1,197.2 |  |  | 1,046.9 |
Cash on hand |  |  |  |  |  |  | 62.5 |  |  | 46.8 |
Total Liquidity and Capital Reserves | $ | 394.7 |  |  | $ | 233.8 |  |  | $ | 568.7 |  |  | $ | 1,259.7 |  |  | $ | 1,093.7 |
1 Includes a $75 million uncommitted standalone letter of credit facility.
2 Includes a $200 million uncommitted standalone letter of credit facility.

On May 23, 2019, the Company fully repaid the remaining outstanding balance of $186.8 million on its corporate term facility in conjunction with the issuance of the Notes (see Long term Debt).
On June 27, 2019, the Company extended its $135.0 million corporate term facility to July 6, 2020 and on December 31, 2019, the Company repaid $60.0 million of the facility.
On July 12, 2019, the Company entered into a new $500.0 million senior unsecured credit facility with a syndicate of banks maturing on July 12, 2024 (the “Corporate Credit Facility”). As at December 31, 2019, the Corporate Credit Facility had $143.0 million drawn and had $37.3 million of outstanding letters of credit issued.
On October 24, 2019 the Company entered into a new $75.0 million uncommitted bilateral letter of credit facility. The facility matures on October 24, 2020.
As at December 31, 2019, Regulated Services Group’s $500.0 million senior unsecured syndicated revolving credit facility (the “Regulated Services Credit Facility”) was undrawn and had $48.2 million of outstanding letters of credit. The Regulated Services Credit Facility matures on February 23, 2023. On July 1, 2019, the Regulated Services Group established a commercial paper program which is backstopped by the Regulated Services Credit Facility. As at December 31, 2019, $218.0 million of commercial paper was issued and outstanding.
As at December 31, 2019, the Renewable Energy Group’s bank lines consisted of a $500.0 million senior unsecured syndicated revolving credit facility (the “Renewable Energy Credit Facility”) maturing on October 6, 2023 and a $200.0 million letter of credit facility (“Renewable Energy LC Facility”) maturing on January 31, 2021. As at December 31, 2019, the Renewable Energy Credit Facility was undrawn and had $6.3 million in outstanding letters of credit. As at December 31, 2019, the Renewable Energy LC Facility had $125.0 million in outstanding letters of credit. Subsequent to year-end, on February 24, 2020, the Renewable Energy Group increased its uncommitted Renewable Energy LC Facility to $350.0 million and extended the maturity to June 30, 2021.

Management Discussion & Analysis – APUC 2019 Annual Report | 34

Long Term Debt
Issuance of Senior Notes
On January 29, 2019, the Renewable Energy Group issued C$300.0 million of senior unsecured debentures bearing interest at 4.60% and with a maturity date of January 29, 2029. The debentures were sold at a price of $999.52 per $1000.00 principal amount. The debentures represent Renewable Energy Group’s inaugural “green bond” offering, and are closely aligned with the Company’s commitment to advancing a sustainable energy and water future.
Subsequent to year-end on February 14, 2020, Liberty Utilities (Canada) LP, the holding company of New Brunswick Gas, issued C$200.0 million of senior unsecured debentures bearing interest at 3.315% and with a maturity date of February 14, 2050. The debentures received a rating of BBB from DBRS. The debentures represent Liberty Utilities (Canada) LP’s inaugural offering with proceeds used to partially repay its parent company APUC for the purchase of New Brunswick Gas which occurred on October 1, 2019.
Issuance of Subordinated Notes
On May 23, 2019, APUC issued $350.0 million of 6.20% fixed-to-floating subordinated notes. Concurrent with the offering, APUC entered into a cross currency swap to convert the U.S. dollar denominated coupon and principal payments from the offering into Canadian dollars, resulting in an effective interest rate to the Company throughout the fixed-rate period of the Notes of approximately 5.96%.
The Notes mature 60 years from issuance and are callable on or after year 5. For the initial 5 years, the Notes carry a fixed interest rate of 6.20%. Subsequently, the interest rate will be set to equal the three-month London Interbank Offered Rate (“LIBOR”) plus a margin of 401 basis points from years 5 to 10, a margin of 426 basis points from years 10 to 30 and a margin of 501 basis points from years 30 to 60. The Notes were initially assigned a rating of BB+/BB+ from S&P and Fitch. The Notes were treated by both rating agencies as hybrid capital, receiving up to 50% equity credit for the balance outstanding. The Notes contain a 102% of par call feature in the event of a rating methodology change by either agency that would reduce the amount of the equity credit.
This offering represents APUC’s second issuance into the U.S. public debt markets. The Notes are listed on the NYSE under the ticker symbol “AQNB”.
As at December 31, 2019, the weighted average tenor of APUC’s total long term debt is approximately 20 years with an average interest rate of 4.9%.
Credit Ratings
APUC has a long term consolidated corporate credit rating of BBB from Standard & Poor’s (“S&P”), a BBB rating from DBRS and a BBB issuer rating from Fitch.
Liberty Utilities Co. (“LUCo”), the parent company for the U.S. regulated utilities under the Regulated Services Group, has a corporate credit rating of BBB from S&P and a BBB issuer rating from Fitch. Debt issued by Liberty Finance, a special purpose financing entity of LUCo, has a rating of BBB (high) from DBRS and BBB+ from Fitch. Empire has an issuer rating of BBB from S&P and a Baa1 rating from Moody’s Investors Service, Inc. (“Moody’s”).
Liberty Utilities (Canada) LP, the parent company for the Canadian regulated utilities under the Regulated Services Group has an issuer rating of BBB from DBRS.
Liberty Power, the parent company for the U.S. and Canadian generating assets under the Renewable Energy Group, has a BBB issuer rating from S&P, a BBB issuer rating from DBRS and a BBB issuer rating from Fitch.

Management Discussion & Analysis – APUC 2019 Annual Report | 35

Contractual Obligations
Information concerning contractual obligations as of December 31, 2019 is shown below:

(all dollar amounts in $ millions) | Total |  | Due in less than 1 year |  | Due in 1 to 3 years |  | Due in 4 to 5 years |  | Due after 5 years
Principal repayments on debt obligations1,2 | $ | 3,931.8 |  |  | $ | 602.0 |  |  | $ | 468.7 |  |  | $ | 600.7 |  |  | $ | 2,260.4 |
Convertible debentures | 0.3 |  |  | — |  |  | — |  |  | — |  |  | 0.3 |
Advances in aid of construction | 60.9 |  |  | 1.2 |  |  | — |  |  | — |  |  | 59.7 |
Interest on long-term debt obligations2 | 1,753.2 |  |  | 185.2 |  |  | 318.5 |  |  | 257.4 |  |  | 992.1 |
Purchase obligations | 458.3 |  |  | 458.3 |  |  | — |  |  | — |  |  | — |
Environmental obligations | 58.5 |  |  | 15.0 |  |  | 20.9 |  |  | 1.1 |  |  | 21.5 |
Derivative financial instruments: |  |  |  |  |  |  |  |  |
Cross currency and forward starting interest rate swaps | 81.8 |  |  | 4.1 |  |  | 69.1 |  |  | 3.9 |  |  | 4.7 |
Energy derivative and commodity contracts | 2.9 |  |  | 1.6 |  |  | 0.9 |  |  | — |  |  | 0.4 |
Purchased power | 256.3 |  |  | 30.7 |  |  | 22.8 |  |  | 23.4 |  |  | 179.4 |
Gas delivery, service and supply agreements | 416.8 |  |  | 83.1 |  |  | 109.9 |  |  | 87.9 |  |  | 135.9 |
Service agreements | 516.0 |  |  | 48.0 |  |  | 82.0 |  |  | 92.6 |  |  | 293.4 |
Capital projects | 219.6 |  |  | 104.8 |  |  | 114.8 |  |  | — |  |  | — |
Land easements | 234.7 |  |  | 6.6 |  |  | 13.4 |  |  | 13.8 |  |  | 200.9 |
Other obligations | 153.0 |  |  | 39.1 |  |  | 2.1 |  |  | 2.7 |  |  | 109.1 |
Total Obligations | $ | 8,144.1 |  |  | $ | 1,579.7 |  |  | $ | 1,223.1 |  |  | $ | 1,083.5 |  |  | $ | 4,257.8 |

1 | Exclusive of deferred financing costs, bond premium/discount, fair value adjustments at the time of issuance or acquisition.
2 | The subordinated notes have a maturity in 2078 and 2079, however management intends to repay in 2023 and 2029 upon exercising its redemption right.

Management Discussion & Analysis – APUC 2019 Annual Report | 36

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 February 26, 2020, APUC had 525,624,407 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.
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, 2019, APUC had outstanding:

• | 4,800,000 cumulative rate reset Series A preferred shares, yielding 5.162% annually for the five-year period ending on December 31, 2023;

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

• | 4,000,000 cumulative rate reset Series D preferred shares, yielding 5.091% annually for the five year period ending on March 31, 2024.

On October 16, 2019, APUC closed the sale of 23.0 million of its common shares for total gross proceeds of $310.5 million, before deducting underwriting commissions and other offering expenses payable by APUC. APUC also granted the underwriters an option to purchase up to an additional 3.5 million common shares of the Company for a period of 30 days. On October 21, 2019, APUC closed the sale of approximately 3.3 million of its common shares for total gross proceeds of $43.9 million, before deducting underwriting commissions payable by APUC.
The proceeds of the Offering were or will be used (as applicable) to partially finance certain of the Company’s previously announced acquisitions and to partially finance the Company’s renewable development growth projects, and for general corporate purposes.
Dividend Reinvestment Plan
APUC has a shareholder dividend reinvestment plan (the “Reinvestment Plan”) for registered holders of common shares of APUC. As at December 31, 2019, 123,468,295 common shares representing approximately 24% of total common shares outstanding had been registered with the Reinvestment Plan. During the year ended December 31, 2019, 6,068,465 common shares were issued under the Reinvestment Plan, and subsequent to year-end, on January 15, 2020, an additional 1,244,696 common shares were issued under the Reinvestment Plan.
At-The-Market Equity Program
On February 28, 2019, APUC established an at-the market equity program (“ATM Program”) that allows APUC to issue up to $250.0 million (or the equivalent in Canadian dollars) of common shares from treasury to the public from time to time, at APUC’s discretion, at the prevailing market price when issued on the TSX, the NYSE, or on any other existing trading market for the common shares of the Company in Canada or the United States. The ATM Program will be effective until October 19, 2020 unless terminated prior to such date by APUC or otherwise in accordance with the terms of the equity distribution agreement dated February 28, 2019.
The ATM Program provides APUC with additional financing flexibility should it be required in the future. The volume and timing of distributions under the ATM Program, will be determined at APUC’s sole discretion. The net proceeds, will be used to fund acquisitions, general and administrative expenses, working capital needs, repayment of indebtedness, and/or other general corporate purposes.
As at February 27, 2020, the Company has issued 1,756,799 common shares under the ATM Program at an average price of $12.54 per share for gross proceeds of approximately $22.0 million ($21.7 million net of commissions). Other related costs, primarily related to the establishment of the ATM Program, were $2.1 million.
SHARE-BASED COMPENSATION PLANS
For the twelve months ended December 31, 2019, APUC recorded $10.6 million in total share-based compensation expense as compared to $9.5 million for the same period in 2018. 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.

Management Discussion & Analysis – APUC 2019 Annual Report | 37

As at December 31, 2019, total unrecognized compensation costs related to non-vested options and share unit awards were $1.3 million and $12.8 million, respectively, and are expected to be recognized over a period of 1.68 and 1.86 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 an expense on a straight-line basis over the options’ vesting periods while ensuring that the cumulative amount of compensation cost recognized at least equals the value of the vested portion of the award at that date. During the twelve months ended December 31, 2019, the Company granted 1,113,775 options to executives of the Company. The options allow for the purchase of common shares at a weighted average price of C$14.96, the market price of the underlying common share at the date of grant. During the year, executives of the Company exercised 841,288 stock options at a weighted average exercise price of C$11.23 in exchange for common shares issued from treasury and 3,041,217 options were settled at their cash value as payment for the exercise price and tax withholdings related to the exercise of the options.
As at December 31, 2019, a total of 3,523,912 options were issued and outstanding under the stock option plan.
Performance Share Units
APUC issues performance share units (“PSUs”) and restricted share units (“RSUs”) to certain members of management as part of APUC’s long-term incentive program. During the twelve months ended December 31, 2019, the Company granted (including dividends and performance adjustments) 1,471,442 PSUs and RSUs to executives and employees of the Company. During the year, the Company settled 344,340 PSUs, of which 142,473 PSUs were exchanged for common shares issued from treasury and 143,078 PSUs were settled at their cash value as payment for tax withholdings related to the settlement of the PSUs. Additionally, during 2019, a total of 107,191 PSUs were forfeited.
As at December 31, 2019, a total of 2,412,043 PSUs and RSUs were granted and outstanding under the PSU and RSU plans.
Directors’ Deferred Share Units
APUC has a Directors’ Deferred Share Unit Plan. Under the plan, non-employee directors of APUC receive all or any portion of their annual compensation in deferred share units (“DSUs”) and may elect to receive any portion of their remaining compensation in DSUs. The DSUs provide for settlement in cash or 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, 2019, the Company issued 79,762 DSUs (including DSUs in lieu of dividends) to the directors of the Company.
As at December 31, 2019, a total of 460,418 DSUs had been granted under the DSU plan.
Bonus Deferral Restricted Share Units
The Company has a bonus deferral restricted share units (“RSUs”) program that is available to certain employees. The eligible employees have the option to receive a portion or all of their annual bonus payment in RSUs in lieu of cash. The RSUs provide for settlement in shares, and therefore these options are accounted for as equity awards. During the twelve months ended December 31, 2019, 262,390 RSUs were issued (including RSUs in lieu of dividends) to employees of the Company.
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, 2019, the Company issued 253,538 common shares to employees under the ESPP.
As at December 31, 2019, a total of 1,285,789 shares had been issued under the ESPP.

Management Discussion & Analysis – APUC 2019 Annual Report | 38

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 liquidity 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
Equity-method investments
The Company entered in a number of transactions with equity-method investees in 2019 and 2018 (see Note 8 in the annual audited consolidated financial statements).
The Company provides administrative and development services to its equity-method investees and is reimbursed for incurred costs. To that effect, the Company charged its equity-method investees $12.4 million in 2019 as compared to $11.4 million during the same period in 2018 (see Note 8(d) and 8(e) in the annual audited consolidated financial statements).
On December 30, 2019, the Company sold its interest in AWUSA VR Holding LLC (“AWUSA”) to a joint venture entity in exchange for a note receivable of $30.3 million (see Note 8(c) in the annual audited consolidated financial statements). No gain or loss was recognized on the sale. For the year, APUC recorded interest income of $6.0 million and a fair value loss of $6.0 million on its investment in the joint venture.
During the year, the Company sold the Sugar Creek Wind Project to AAGES in exchange for a note receivable of $21.1 million, subject to certain adjustments. No gain was recorded on deconsolidation of the Sugar Creek Wind Project net assets. However, an amount of $15.8 million or $11.4 million, net of tax was reclassified from AOCI into earnings as a result of the discontinuation of hedge accounting on energy derivatives put in place early in the development of the Sugar Creek Wind Project (see Note 24(b)(ii) in the annual audited consolidated financial statements).
During the year, the Company entered into an enhanced cooperation agreement with Atlantica to, among other things, provide a framework for evaluating mutually advantageous transactions. For a period of one year from the date of the agreement, Atlantica has an exclusive right of first offer for interests in certain Renewable Energy Group assets.
Redeemable non-controlling interest held by related party
Redeemable non-controlling interest held by related party represents a preference share in a consolidated subsidiary of the Company acquired by AAGES in 2018 for $305.0 million (see Note 8(a) in the annual audited consolidated financial statements). Redemption is not considered probable as at December 31, 2019. The Company incurred non-controlling interest attributable to AAGES of $16.5 million as compared to $2.6 million during the same period in 2018 and recorded distributions of $18.2 million as compared to $nil during the same period in 2018 (see Note 17 in the annual audited consolidated financial statements).
Non-controlling interest held by related party
Non-controlling interest held by related party represents interest in a consolidated subsidiary of the Company acquired by a subsidiary of Atlantica in May 2019 for $96.8 million (see Note 8(b) in the annual audited consolidated financial statements). The Company recorded distributions of $26.5 million during the year.

Management Discussion & Analysis – APUC 2019 Annual Report | 39

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.
ENTERPRISE RISK MANAGEMENT
The Corporation is subject to a number of risks and uncertainties, certain of which are described below. A risk is the possibility that an event might happen in the future that could have a negative effect on the financial condition, financial performance or business of the Corporation. The actual effect of any event on the Corporation’s business could be materially different from what is anticipated or described below. The description of risks below does not include all possible risks.
Led by the Chief Compliance and Risk Officer, the Corporation has an established enterprise risk management, or (“ERM”), framework. The Corporation’s ERM framework follows the guidance of ISO 31000 and the Committee of Sponsoring Organizations of the Treadway Commission (“COSO”) Enterprise Risk Management - Integrated Framework. The Corporation’s ERM framework is intended to systematically identify, assess, and mitigate 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 Board-approved ERM policy details the Corporation’s risk management processes, risk appetite, and risk governance structure.
As part of the risk management process, risk registers have been developed across the organization through ongoing risk identification and risk assessment exercises facilitated by the Corporation’s internal ERM team. Key risks and associated mitigation strategies are reviewed by the executive-level Enterprise Risk Management Council and are presented to the Board’s Risk Committee periodically.
Risks are evaluated consistently across the Corporation using a standardized 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 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’ risk factors are set out in the Company’s most recent AIF available on SEDAR and EDGAR. The risks discussed below are intended to provide an update on those that were previously disclosed.
Treasury Risk Management
Downgrade in the Company’s Credit Rating Risk
APUC has a long term consolidated corporate credit rating of BBB from S&P, a BBB rating from DBRS and a BBB issuer rating from Fitch. Liberty Power, the parent company for the U.S. and Canadian generating assets under the Renewable Energy Group, has a BBB issuer rating from S&P, BBB issuer rating from DBRS and a BBB issuer rating from Fitch. LUCo, the parent company for the U.S. regulated utilities under the Regulated Services Group, has a corporate credit rating of BBB from S&P and a BBB issuer rating from Fitch. Debt issued by Liberty Finance, a special purpose financing entity of LUCo, has a rating of BBB (high) from DBRS and BBB+ from Fitch. Empire has a BBB issuer rating from S&P and a Baa1 issuer rating from Moody’s. Liberty Utilities (Canada) LP, the parent company for the Canadian regulated utilities under the Regulated Services Group has an issuer rating of BBB from DBRS.
The ratings indicate the agencies’ assessment of the ability to pay the interest and principal of debt securities issued by such entities. A rating is not a recommendation to purchase, sell or hold securities and each rating should be evaluated independently of any other rating. The lower the rating, the higher the interest cost of the securities when they are sold. A downgrade in 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. Any such downgrade could also adversely impact the market price of the outstanding securities of the Company, could impact the Company’s ability to acquire additional regulated utilities and could require the Company to post additional collateral security under some of its contracts and hedging arrangements. If any of APUC’s ratings fall below investment grade (investment grade is defined as BBB- or above for S&P and Fitch, BBB (low) or above for DBRS and Baa3 or above for Moody’s), APUC’s ability to issue short-term debt or other securities or to market those securities would be constrained or made more difficult or expensive. Therefore, any 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.

Management Discussion & Analysis – APUC 2019 Annual Report | 40

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. Each rating agency employs proprietary scoring methodologies that assess business and financial risks of the entity rated. There can be no assurance that the principles of the rating remain consistently applied, and these principles are subject to change from time to time at each rating agency’s discretion. For example, a rating agency’s views on total allowable leverage, specific industry risk factors, country risk and the company’s business mix, amongst other factors, may change. Such changes could require APUC to adjust its business and strategy in order to maintain its credit ratings. APUC currently anticipates that to continue to maintain a BBB flat investment grade credit ratings, it will, amongst other things, need to execute its growth strategy in a manner that preserves satisfaction of financial leverage targets and continues to generate no less than approximately its current portion of EBITDA (as determined by applicable rating agency methodologies) from APUC’s Regulated Services Group. There can be no assurance that APUC will be successful, and the failure to do so could have a negative impact on APUC’s credit ratings. The business mix target may from time to time require APUC to grow its Regulated Services Group or implement other strategies in order to pursue investment opportunities within its Renewable Energy Group.
Capital Markets and Liquidity Risk
As at December 31, 2019, the Company had approximately $3,932.2 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 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 favourable terms may be adversely affected by adverse financial and operational performance, or 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 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; 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; 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 favourable than the current terms, the Company’s cashflows and 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 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 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.

Management Discussion & Analysis – APUC 2019 Annual Report | 41

Based on amounts outstanding as at December 31, 2019, 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 $143.0 million outstanding as at December 31, 2019. As a result, a 100 basis point change in the variable rate charged would impact interest expense by $1.4 million annually;

● | The Regulated Services Group’s commercial paper program is subject to a variable interest rate and had $218.0 million outstanding as at December 31, 2019. As a result, a 100 basis point change in the variable rate charged would impact interest expense by $2.2 million annually;

● | The corporate term facilities are subject to a variable interest rate and had $75.0 million outstanding as at December 31, 2019. As a result, a 100 basis point change in the variable rate charged would impact interest expense by $0.8 million annually.

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 it does business could adversely affect the Company’s results from operations, returns 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 cost amount of the Company’s depreciable properties. A successful challenge by an applicable taxation authority regarding such tax positions could adversely affect the results of operations and financial position of the Company.
Development by the Company of renewable power generation facilities in the United States depends in part on federal tax credits and other tax incentives. These credits are currently subject to a multi-year step-down. While recently enacted U.S. Tax Reform legislation did extend some of the credits, at reduced levels, for renewable power generation facilities that begin construction in 2020, there can be no assurance that there will be further extensions in the future or whether the reduced credits are sufficient to support continued development and construction of renewable power facilities in the United States. Moreover, if the Company is unable to complete construction on current or planned projects on anticipated schedules, the incentives may no longer be available or substantially reduced which may be insufficient to support continued development or may result in substantially reduced financial benefits from facilities or long-term investment in facilities (potentially resulting in a write down of a portion of a facility whether held directly or through an equity investee) that the Company is committed to complete. In addition, the Company has entered into certain tax equity financing transactions with financial partners for certain of its renewable power facilities in the United States, under which allocations of future cash flows to the Corporation from the applicable facility could be adversely affected in the event that there are changes in U.S. tax laws that apply to facilities previously placed in service.
U.S. Tax Reform
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 affect the Company. The U.S. Department of Treasury has released proposed regulations related to business interest expense limitations, Base Erosion Anti-Abuse Tax, and anti-hybrid structures as part of the implementation of U.S. Tax Reform. Some of the proposed regulations were finalized during 2019. Many of the regulations are still in proposed form and are subject to change in the regulatory review process which is expected to be completed during 2020. The timing or impacts of any future changes in tax laws, including the impacts of proposed regulations, cannot be predicted. As a result, there may be future impacts on the results of operations, financial condition and cash flows of the Company.

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Credit/Counterparty Risk
APUC and its subsidiaries, through its long term PPA’s, 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.
The following chart sets out the Company’s 10 largest customers and their credit ratings:

Counterparty | Credit Rating 1 | Approximate Annual Revenues | Percentage of APUC Revenue
PJM Interconnection LLC | Aa2 | $ | 25.6 |  | 1.6 | %
Manitoba Hydro | A+ | 22.4 |  | 1.4 | %
Hydro Quebec | Aa2 | 20.4 |  | 1.3 | %
Commonwealth Edison | A- | 22.1 |  | 1.4 | %
Xcel Energy | Baa1 | 17.5 |  | 1.1 | %
Pacific Gas and Electric Company | D | 18.9 |  | 1.2 | %
Wolverine Power Supply | A | 23.6 |  | 1.5 | %
Ontario Electricity Financial Corporation (OEFC) | Aa3 | 16.1 |  | 1.0 | %
Connecticut Light and Power | A3 | 19.9 |  | 1.2 | %
Independent Electricity System Operator (IESO) of Ontario | Aa3 | 15.9 |  | 1.0 | %
Total |  | $ | 202.4 |  |  |

1 | Ratings by DBRS, Moody’s, or S&P.

The Renewable Energy Group’s revenues are approximately 15% of total Company revenues. Approximately 87% of the Renewable Energy 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 remaining revenue of the Company is primarily earned by the Regulated Services Group. In this regard, the credit risk attributed to the Regulated Services Group’s accounts receivable balances at the water and wastewater distribution systems total $22.1 million which is spread over approximately 168,000 connections, resulting in an average outstanding balance of approximately $130 dollars per connection.
The natural gas distribution systems accounts receivable balances related to the natural gas utilities total $99.3 million, while electric distribution systems accounts receivable balances related to the electric utilities total $90.8 million. The natural gas and electrical utilities both derive over 80% of their revenue from residential customers and have a per connection average outstanding balance of $269 dollars and $340 dollars respectively.
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 offset by bad debt reserves approved by the applicable utility regulator. If a customer under a long-term PPA with the Renewable Energy Group is unable to perform, the Renewable Energy Group may be unable to replace the contract on comparable terms, in which case sales of power (and, if applicable, RECs and ancillary services) from the facility would be subject to market price risk and may require refinancing of indebtedness related to the facility or otherwise have a material adverse effect. Default by other counterparties, including 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 Renewable Energy Group assets subject to long term PPA’s are not exposed to market risk for this portion of its portfolio. Where a generating asset is not covered by a PPA, the Renewable Energy Group may seek to mitigate market risk exposure by entering into financial or physical power hedges requiring that a specified amount of power be delivered at a specified time in return for a fixed price. There is a risk that the Company is not able to generate the specified amount of power at the specified time resulting in production shortfalls under the hedge that then requires the Company to purchase power in the merchant market. To mitigate the risk of production shortfalls under hedges, the Renewable Energy Group generally seeks to structure hedges to cover less than 100% of the anticipated production, thereby reducing the risk of not producing the minimum hedge quantities. Nevertheless, due to unpredictability in the natural resource or due to grid curtailments or mechanical failures, production shortfalls may be such that the Renewable Energy Group may still be forced to purchase power in the merchant market at prevailing rates to settle against a hedge.

Management Discussion & Analysis – APUC 2019 Annual Report | 43

Hedges currently put in place by the Renewable Energy Group for its operating facilities along with residual exposures to the market are detailed below:
The Minonk, Senate and Sandy Ridge Wind Facilities with a combined annual LTAR of 1,352 GW-hrs have financial hedges in place until the end of 2025 which are structured to hedge an average of 66.3% of annual LTAR against exposure to the applicable hub current spot market rates. The annual average unhedged production based on LTAR is approximately 455 GW-hrs annually.
Under each of the above noted hedges, if production is not sufficient to meet the unit quantities under the hedge, the shortfall must be purchased in the open market at market rates. The effect of this risk exposure could be material 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 Renewable Energy Group enters into short-term derivative contracts (usually with terms of one to three months) to further mitigate market price risk exposure due to production variability. As at December 31, 2019, the Renewable Energy Group had entered into hedges with a cumulative notional quantity of 148,520 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 $10 per MW-hr change in market prices would result in a change in revenue of approximately $0.5 million for the year.
The Company has elected the fair value option under ASC 825, Financial Instruments to account for its investment in Atlantica, with changes in fair value reflected in the annual audited consolidated statement of operations. As a result, each dollar change in the traded price of Atlantica shares will correspondingly affect the Company’s Net Earnings by approximately $44.9 million.
Commodity Price Risk
The Regulated Services Group is exposed to energy and natural gas price risks at its electric and natural gas systems. The Renewable Energy Group’s exposure to commodity prices is primarily limited to exposure to natural gas price risk. In this regard, a discussion of these risks are set out as follows:
Regulated Services Group
The CalPeco Electric System provides electric service to the Lake Tahoe California basin and surrounding areas at rates approved by the California Public Utilities Commission (“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 Default Service customers. The winning bidder is obligated to provide a full requirements service based on the actual needs of the Granite State Electric System’s Default Service customers. Since this is a full requirements service, the winning bidder(s) take on the risk associated with fluctuating customer usage and commodity prices. The supplier is paid for the commodity by the Granite State Electric System which in 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 commonly 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 18% 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

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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, storage 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 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. Similar to the Midstates Gas Systems, the Empire Gas System serves customers in Missouri, and also implements a commodity hedging program designed to hedge 70 to 90% of its winter demand inclusive of storage volumes withdrawn during the winter period. All related costs are embedded in approved rates and are passed-through to customers in the PGA. The Empire Gas System is permitted to file an Actual Cost Adjustment (“ACA”) once a year which also includes a PGA filing. In addition to the ACA filing, three more optional PGA filings are allowed during the year. The Empire Gas Systems ACA year is from September 1 to August 31 for each year.
The Georgia (Peach State) Gas System purchases pipeline capacity, storage and commodity from a variety of counterparties, and files with the Georgia Public Service Commission (“PSC”) for recovery of its transportation, storage and commodity costs through a monthly PGA filing process. The Peach State Gas System establishes rates for its customers within the PGA filings and these rates are designed to fully recover its anticipated transportation, storage and commodity costs. In order to minimize commodity price fluctuations, the annual Gas Supply Plan filed by the Company and approved by the Georgia PSC includes a commodity hedging program designed to hedge approximately 30% of its non-storage related commodity purchases during the winter months. All gains and losses associated with the hedging program are passed through to customers in the PGA filings and are embedded in the approved rates in such filings. Rates can be adjusted on a monthly basis in order to account for any differences in gas costs relative to the amounts assumed in the PGA filings, minimizing any under or over collection of its gas costs.
The Empire Electric System 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. The Empire Electric System met approximately 41% of its 2019 generation fuel supply need through coal. Approximately 97% of its 2019 coal supply was Western coal. The Empire Electric System had contracts and binding proposals to supply a portion of the fuel for its coal plants through 2019. Those contracts and inventory on hand satisfied the anticipated fuel requirements for the Asbury Coal Facility. The Asbury Coal Facility is scheduled to be retired in March 2020.
The Empire Electric Systems natural gas procurement program for electrical generation is designed to manage costs to mitigate volatile natural gas prices. The Empire Electric System periodically enters into fixed price contracts with counterparties to hedge future natural gas prices in an attempt to lessen the volatility in fuel expenditures. Generally, the over/under variances associated with the hedging program are passed through to customers in the fuel adjustment clause assuming they are deemed to be prudently incurred.
Renewable Energy Group
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 $0.1 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 $0.4 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 190,000 MW-hrs in fiscal 2020, of which 181,000 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 41,000 MW-hrs of its energy requirements at the ISO-NE spot rates to supplement self-generated energy should the Maritime region not be able to reach the estimated 190,000 MW-hrs. The risk associated with the expected market purchases of 41,000 MW-hrs is mitigated through the use of financial energy hedge contracts which cover all of the Maritime region’s anticipated purchases during the year at an average rate of approximately $39 per MW-hr.

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OPERATIONAL RISK MANAGEMENT
Succession Planning and Leadership Development
On February 5, 2020, APUC announced the appointment of Arun Banskota to the newly-created position of President. Mr. Banskota will work closely with Chief Executive Officer Ian Robertson and other members of the Executive Team to transition into the role of Chief Executive Officer in 2020.
APUC also announced that David Bronicheski, Chief Financial Officer, is retiring in the fall of 2020, and that Arthur Kacprzak, Vice President, Treasury and Treasurer, has been promoted to Senior Vice President and Deputy Chief Financial Officer.
There can be no assurance that leadership transitions will be successful and the transitions may have an adverse impact to APUC and its business.
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, diseases (including the 2019 Novel Coronavirus) and other force majeure events, interruption in supply chain and expenses related to claims or clean-up to adhere to environmental and safety standards.
The Regulated Services Group’s water and wastewater distribution systems operate under pressurized conditions within pressure ranges approved by regulators. Should a water distribution network become compromised or damaged, the resulting release of pressure could result in serious injury or death to individuals or damage to other property.
The Regulated Services Group’s electric distribution systems are subject to storm events, usually winter storm events, whereby power lines can be brought down, with the attendant risk to individuals and property. In addition, in forested areas, power lines brought down by wind can ignite forest fires which also bring attendant risk to individuals and property.
The Regulated Services Group’s natural gas distribution systems are subject to risks which may lead to fire and/or explosion which may impact life and property. Risks include third party damage, compromised system integrity, type/age of pipelines, and severe weather events.
The Renewable Energy 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 Renewable Energy 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 Renewable Energy 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 Renewable Energy Group’s electric generating stations are subject to mechanical breakdown. The risk of mechanical breakdown is mitigated by properly maintaining the units and by regular inspections.
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 of Renewable Energy Group’s hydroelectric facilities, water rights are generally owned by governments that reserve the right to control water levels, which may affect revenue.
The Regulated Services Group’s facilities are subject to rate setting by state regulatory agencies. The Regulated Services Group operates in 13 different states and 1 province and therefore is subject to regulation from 14 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

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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 Regulated Services Group seeks to obtain approval for regulatory constructs in the states in which it operates to allow for timely recovery of operating expenses. 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 Regulated Services 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 has had an impact on regulatory revenue requirements of most public utilities, including the Regulated Services Group. The Regulated Services Group obtained orders from the majority of its principal regulators, resulting in the reduction of customer rates in connection with the reduction in tax rates. Since the Company has not yet received rate orders addressing all matters related to U.S. Tax Reform for all of its utilities, the full impact of rate reductions related to U.S. Tax Reform is not known.
Condemnation Expropriation Proceedings
The Regulated Services Group’s distribution systems could be subject to condemnation or other methods of taking by government entities under certain conditions. Any taking by government entities would legally require fair compensation to be paid. Determination of such fair compensation is undertaken pursuant to a legal proceeding and, therefore, there is no assurance that the value received for assets taken will be in excess of book value.
Apple Valley Condemnation Proceedings
On January 7, 2016, the Town of Apple Valley filed a lawsuit seeking to condemn the utility assets of the Regulated Services Group (Apple Valley Ranchos Water) Corp (“Liberty Apple Valley”). The lawsuit will be adjudicated in phases. In the first phase, the Court will determine whether to allow the taking by the Town; under California law, the taking will be allowed unless Liberty Apple Valley proves there is not a “public necessity” for the taking. If Liberty Apple Valley prevails, the case is concluded and the Town will be required to compensate Liberty Apple Valley for its litigation expenses. However, if the Court determines that the taking is allowed, there will be a second phase of the trial in which a jury will determine the amount of compensation owed for the taking based upon the fair market value of the assets being condemned. The right to take trial began on October 23, 2019, and is expected to continue until March 2020 with a judicial decision on the right to take expected in the third quarter of 2020. If, following that trial, there is a need for a second phase to determine compensation, that trial can be expected to occur six to twelve months after the conclusion of the first phase.
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 failure to obtain required approvals, 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.
The Company’s growth strategy may be constrained by factors associated with the maintenance of its BBB flat investment grade credit ratings. These factors include: (i) constraints on maximum leverage, (ii) the proportion of EBITDA (as determined by applicable rating agency methodologies) required to be generated from the Regulated Services Group, and (iii) the geographies in which APUC can operate in scale. There can be no assurance that these constraints will not negatively impact the Company’s ability to successfully execute on available growth opportunities. The business mix target may from time to time require APUC to grow its Regulated Services Group or implement other strategies in order to pursue investment opportunities within its Renewable Energy Group.
International Investment Risk
The Company’s investment in Atlantica exposes the Company to certain risks that are particular to Atlantica’s business and the markets in which Atlantica operates.
Atlantica owns, manages and acquires renewable energy, conventional power, electric transmission lines and water assets in certain jurisdictions where the Company may not operate. The Company, through its investment in Atlantica, is indirectly

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exposed to certain risks that are particular to the markets in which it operates, including, but not limited to, risks related to: conditions in the global economy; changes to national and international laws, political, social and macroeconomic risks relating to the jurisdictions in which Atlantica operates, including in emerging markets, which could be subject to economic, social and political uncertainties; anti-bribery and anti-corruption laws and substantial penalties and reputational damage from any non-compliance therewith; significant currency exchange rate fluctuations; Atlantica’s ability to identify and/or consummate future acquisitions on favourable terms or at all; Atlantica’s inability to replace, on similar or commercially favourable terms, expiring or terminated offtake agreements; termination or revocation of Atlantica’s concession agreements or PPAs; and various other factors. These risks could affect the profitability and growth of Atlantica’s business, and ultimately the profitability of the Company’s anticipated investment therein.
The Company’s international acquisition, development, construction and operating activities, including through the AAGES joint venture, expose the Company to similar risks and could likewise affect the profitability, financial condition and growth of the Company.
Risks Specific to the Atlantica Investment
The Company accounts for its investment in Atlantica using the Fair Value Method (see Note 1(n) in the audited consolidated financial statements). APUC records in the consolidated statements of operations the fluctuations in the fair value of Atlantica shares and dividend income when it is declared. During 2019, Atlantica announced it is undertaking a strategic review process. The results of this process have not yet been announced and the outcome is uncertain. Atlantica’s share price may be adversely affected by the outcome of the strategic review, which would in turn could negatively affect APUC’s results.
Joint Venture Investment Risk
The Company has, and in the future may continue to have, an interest in projects over which it does not have sole control, which may create a risk that the Company’s joint venture partner may:

• | have economic or business interests or goals that are inconsistent with the Company’s economic or business interests or goals;

• | take actions contrary to the Company’s policies or objectives with respect to the Company’s investments;

• | contravene applicable anti-bribery laws that carry substantial penalties for non-compliance and could cause reputational damage and a material adverse effect on the business, financial position and results of operations of the joint venture and the Company;

• | have to give its consent with respect to certain major decisions, including among others, decisions relating to funding and transactions with affiliates;

• | become bankrupt, limiting its ability to meet calls for capital contributions and potentially making it more difficult to refinance or sell projects;

• | become engaged in a dispute with the Company that might affect the Company’s ability to develop a project; or

• | have competing interests in the Company’s markets that could create conflict of interest issues.

The Company’s involvement with AAGES may also present a reputational risk, including from the reputation of Abengoa. AAGES has obtained a 3 year secured credit facility in the amount of $306.5 million (“AAGES Credit Facility”), which is collateralized through a pledge of the Atlantica shares. A collateral shortfall would occur if the net obligation as defined in the agreement would equal or exceed 50% of the market value of the Atlantica shares. In the event of a collateral shortfall AAGES is required to post additional collateral in cash to reduce the net obligation to 40% of the total collateral provided (“Collateral Reset Level”). If AAGES were unable to fund the collateral shortfall, the AAGES Credit Facility lenders hold the right to sell Atlantica stock to reduce the facility to the Collateral Reset Level. The AAGES Credit Facility is repayable on demand if Atlantica ceases to be a public company. If AAGES were unable to repay the amounts owed, the lenders would have the right realize on their collateral.
The Company has entered into Equity Capital Contribution Agreements (“ECCA”) with certain of its project development entities it holds an equity interest in. The ECCAs obligate the Company to provide funding upon the realization of certain completion milestones related to the projects under development. The ECCAs have been pledged as collateral against construction loans obtained by the project entities and may require the Company to fund in amounts in excess of the underlying value of the assets. The Company has also provided guarantees of performance for certain development projects owned by the equity investees.
Please refer to Note 8 in the annual audited consolidated financial statements for a description of the Company’s Long Term Investments and Notes Receivable.

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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.
In conjunction with acquisitions and developed projects, the Company assumed certain asset retirement obligations. The asset retirement obligations mainly relate to legal requirements for: (i) removal or decommissioning of power generating facilities; (ii) cut (disconnect from the distribution system), purge (clean of natural gas and PCB contaminants), and cap 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
Regulated Services Group
The Regulated Services Group’s demand for water is affected by weather conditions and temperature. Demand for water during warmer months is generally greater than cooler months due to requirements for irrigation, swimming pools, cooling systems and other outside water use. If there is above normal rainfall or rainfall is more frequent than normal the demand for water may decrease, adversely affecting revenues.
The Regulated Services Group’s demand for energy from its electric distribution systems is primarily affected by weather conditions and conservation initiatives. The Regulated Services Group provides information and programs to its customers to encourage the conservation of energy. In turn, demand may be reduced which could have short term adverse impacts on revenues.
The Regulated Services Group’s primary demand for natural gas from its natural gas distribution systems is driven by the seasonal heating requirements of its residential, commercial, and industrial customers. The colder the weather the greater the demand for natural gas to heat homes and businesses. As such, the natural gas distribution systems demand 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 review proceedings. While not all regulatory jurisdictions have approved mechanisms to mitigate demand fluctuations, to date, the Regulated Services Group has successfully obtained regulatory approval to implement such decoupling mechanisms in 7 of 13 states. An example of such a mechanism is seen at the Peach State Gas System in Georgia, where a weather normalization adjustment is applied to customer bills during the months of October through May that adjusts commodity rates to stabilize the revenues of the utility for changes in billing units attributable to weather patterns.
Renewable Energy Group
The Renewable Energy Group’s hydroelectric operations are impacted by seasonal fluctuations and year to year variability of the available hydrology. These assets are primarily “run-of-river” and as such fluctuate with natural water flows. During the winter and summer periods, flows are generally lower while during the spring and fall periods flows are generally higher. The ability of these assets to generate income may be impacted by changes in water availability or other material hydrologic events within a watercourse. Year to year the level of hydrology varies, impacting the amount of power that can be generated in a year.
The Renewable Energy Group’s wind generation facilities are impacted by seasonal fluctuations and year to year variability of the wind resource. During the fall 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 Renewable Energy 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.
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

Management Discussion & Analysis – APUC 2019 Annual Report | 49

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.
Development by the Renewable Energy Group of renewable power generation facilities in the United States depends in part on federal tax credits and other tax incentives. These incentives are currently subject to a multi-year step-down. The first step down occurs on December 31, 2020. APUC currently has a number of significant projects in construction that could be materially adversely affected if they are not placed in service by this date.
In February 2020, APUC received force majeure notices from certain of its turbine suppliers related to the 2019 Novel Coronavirus outbreak. The notices relate to wind energy projects from both the Regulated Services Group and Renewable Energy Group and a solar project from the Renewable Energy Group. While the exact impacts of the 2019 Novel Coronavirus outbreak on APUC and its projects remain unknown, manufacturing and delivery delays caused by the 2019 Novel Coronavirus could adversely affect its projects, including (a) causing one or more projects scheduled for completion in 2020 to not be placed in service until 2021 or (b) adversely impacting the availability of tax equity or other financing. APUC is working with its suppliers, contractors and advisors in an effort to mitigate the impacts on its projects, but there can be no assurance that such efforts will be successful.
Litigation Risks and Other Contingencies
APUC and certain of its subsidiaries are involved in various litigation, claims and other legal and regulatory proceedings that arise from time to time in the ordinary course of business. Any accruals for contingencies related to these items are recorded in the financial statements at the time it is concluded that a material financial loss is likely and the related liability is estimable. Anticipated recoveries under existing insurance policies are recorded when reasonably assured of recovery.
Claim by Gaia Power Inc.
On October 30, 2018, Gaia Power Inc. (“Gaia”) commenced an action in the Ontario Superior Court of Justice against APUC and certain of its subsidiaries, claiming damages of not less than C$345 million and punitive damages in the sum of C$25 million. The action arises from Gaia’s 2010 sale, to a subsidiary of APUC, of Gaia’s interest in certain proposed wind farm projects in Canada. Pursuant to a 2010 royalty agreement, Gaia is entitled to royalty payments if the projects are developed and achieve certain agreed targets.
The parties have since agreed to arbitrate the matter pursuant to the royalty agreement’s arbitration clause. APUC and the other respondents have delivered their responses to Gaia’s notice of arbitration, and the parties are currently in the process of exchanging documentary productions. It is too early to determine the likelihood of success in this lawsuit, however APUC intends to vigorously defend it.
Information Security 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 and device theft. Should a material breach occur the Company may not be able to recover all costs and losses through insurance, legal or regulatory processes.

Management Discussion & Analysis – APUC 2019 Annual Report | 50

Energy Consumption and Advancement in Technologies Risk
The Regulated Services 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 Regulated Services 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 Regulated Services 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 in accordance with the industry practice. However, there are certain elements of the Regulated Services 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 Regulated Services 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.
QUARTERLY FINANCIAL INFORMATION
The following is a summary of unaudited quarterly financial information for the eight quarters ended December 31, 2019:

(all dollar amounts in $ millions except per share information) | 1st Quarter 2019 |  | 2nd Quarter 2019 |  | 3rd Quarter 2019 |  | 4th Quarter 2019
Revenue | $ | 477.2 |  |  | $ | 343.6 |  |  | $ | 364.4 |  |  | $ | 439.7 |
Net earnings attributable to shareholders | 86.4 |  |  | 156.6 |  |  | 115.8 |  |  | 172.1 |
Net earnings per share | 0.17 |  |  | 0.31 |  |  | 0.23 |  |  | 0.34 |
Diluted net earnings per share | 0.17 |  |  | 0.31 |  |  | 0.23 |  |  | 0.33 |
Adjusted Net Earnings1 | 93.8 |  |  | 54.9 |  |  | 69.0 |  |  | 103.6 |
Adjusted Net Earnings per share1 | 0.19 |  |  | 0.11 |  |  | 0.14 |  |  | 0.20 |
Adjusted EBITDA1 | 231.5 |  |  | 189.8 |  |  | 185.8 |  |  | 231.5 |
Total assets | 9,671.3 |  |  | 10,034.3 |  |  | 10,618.9 |  |  | 10,911.5 |
Long term debt2 | 3,651.9 |  |  | 3,782.3 |  |  | 4,276.6 |  |  | 3,932.2 |
Dividend declared per common share | $ | 0.13 |  |  | $ | 0.14 |  |  | $ | 0.14 |  |  | $ | 0.14 |
| 1st Quarter 2018 |  | 2nd Quarter 2018 |  | 3rd Quarter 2018 |  | 4th Quarter 2018
Revenue | $ | 494.8 |  |  | $ | 366.2 |  |  | $ | 365.6 |  |  | $ | 421.9 |
Net earnings attributable to shareholders | 17.6 |  |  | 65.5 |  |  | 57.9 |  |  | 44.0 |
Net earnings per share | 0.04 |  |  | 0.14 |  |  | 0.12 |  |  | 0.09 |
Diluted net earnings per share | 0.04 |  |  | 0.14 |  |  | 0.12 |  |  | 0.09 |
Adjusted Net Earnings1 | 141.1 |  |  | 50.9 |  |  | 49.7 |  |  | 70.5 |
Adjusted Net Earnings per share1 | 0.30 |  |  | 0.11 |  |  | 0.10 |  |  | 0.14 |
Adjusted EBITDA1 | 279.2 |  |  | 160.3 |  |  | 166.0 |  |  | 198.9 |
Total assets | 8,941.8 |  |  | 8,920.7 |  |  | 9,072.6 |  |  | 9,398.6 |
Long term debt2 | 3,832.7 |  |  | 3,448.1 |  |  | 3,561.3 |  |  | 3,337.3 |
Dividend declared per common share | $ | 0.12 |  |  | $ | 0.13 |  |  | $ | 0.13 |  |  | $ | 0.13 |

1 | See Non-GAAP Financial Measures
2 | Includes current portion of long-term debt, long-term debt and convertible debentures.

The quarterly results are impacted by various factors including seasonal fluctuations and acquisitions of facilities as noted in this MD&A.
Quarterly revenues have fluctuated between $343.6 million and $494.8 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.

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In addition, a factor impacting revenues year over year is the fluctuation in the strength of the Canadian dollar relative to the U.S. dollar which can result in significant changes in reported revenue from Canadian operations.
Quarterly net earnings attributable to shareholders have fluctuated between $17.6 million and $172.1 million over the prior two year period. Earnings have been significantly impacted by non-cash factors such as deferred tax recovery and expense, impairment of intangibles, property, plant and equipment and mark-to-market gains and losses on financial instruments.
SUMMARY FINANCIAL INFORMATION OF ATLANTICA
The Company owns a 44.2% beneficial stake in Atlantica. APUC accounts for its interest in Atlantica using the fair value method (see Note 8(a) in the annual audited consolidated financial statements). The summary financial information of Atlantica in the following table is derived from the audited consolidated financial statements of Atlantica as of December 31, 2019 and 2018 and for the years then ended which are reported in U.S. dollars and were prepared using International Financial Reporting Standards, as issued by the International Accounting Standards Board (“IFRS”). The recognition, measurement and disclosure requirements of IFRS differ from U.S. GAAP as applied by the Company.

(all dollar amounts in $ millions) | 2019 |  | 2018
Revenue | $ | 1,011.5 |  |  | $ | 1,043.8 |
Profit (loss) for the year | 74.6 |  |  | 55.3 |
Total non-current assets | 8,540.6 |  |  | 8,791.3 |
Total current assets | 1,119.2 |  |  | 1,127.7 |
Total non-current liabilities | 6,971.6 |  |  | 7,423.8 |
Total current liabilities | 973.4 |  |  | 739.1 |

DISCLOSURE CONTROLS AND PROCEDURES
APUC’s management carried out an evaluation as of December 31, 2019, 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, 2019, 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 the CFO, is responsible for establishing and maintaining internal control over financial reporting (as defined in Rules 13a-15(f) under the Exchange Act) to provide reasonable, but not absolute, assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with U.S. GAAP.
The Company’s internal control over financial reporting framework includes those policies and procedures that (i) pertain to the maintenance of records that, in reasonable detail, accurately and fairly reflect the transactions and dispositions of the assets of the Company, (ii) provide reasonable assurance that transactions are recorded as necessary to permit preparation of financial statements in accordance with U.S. GAAP, and that receipts and expenditures of the Company are being made only in accordance with authorizations of management and directors of the Company; and (iii) provide reasonable assurance regarding prevention or timely detection of unauthorized acquisition, use or disposition of the Company’s assets that could have a material effect on the Company’s consolidated financial statements.
Due to its inherit 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.
During the year ended December 31, 2019, the Company acquired St. Lawrence Gas and New Brunswick Gas. Management is in the process of evaluating the existing controls and procedures of St. Lawrence Gas and New Brunswick Gas and integrating financial reporting and controls for St. Lawrence Gas and New Brunswick Gas into the Company’s internal control over financial reporting. The financial information for these acquisitions is included in this MD&A and in Note 3 in the annual audited consolidated financial statements. As permitted under applicable laws due to the complexity associated with assessing internal controls during integration efforts, the Company excluded these acquisitions from its evaluation of the effectiveness of the

Management Discussion & Analysis – APUC 2019 Annual Report | 52

Company’s internal controls over financial reporting as of December 31, 2019 (representing approximately 4% of our total assets as of December 31, 2019 and approximately 2% of our revenues for the year ended December 31, 2019). Management assessed the effectiveness of the Company’s internal control over financial reporting as of December 31, 2019, based on the framework established in Internal Control - Integrated Framework (2013) issued by COSO. This assessment included review of the documentation of controls, evaluation of the design effectiveness of controls, testing of the operating effectiveness of controls, and a conclusion on this evaluation. Based on this assessment, management concluded that the Company’s internal control over financial reporting was effective as of December 31, 2019 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, 2019, there has been no change in the Company’s internal controls over financial reporting that has materially affected, or is reasonably likely to materially affect, the Company’s internal controls over financial reporting.
INHERENT LIMITATIONS ON EFFECTIVENESS OF CONTROLS
Due to its inherent limitations, disclosure controls and procedures or internal control over financial reporting may not prevent or detect all misstatements based on error 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.
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 judgment relate to the scope of consolidated entities, 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 in the annual audited consolidated financial statements, respectively. Management believes the following accounting policies involve the application of critical accounting estimates. Accordingly, these accounting estimates have been reviewed and discussed with the Audit Committee of the Board of Directors of APUC.
Consolidation and Variable Interest Entities
The Company uses judgment to assess whether its operations or investments represent variable interest entities (“VIEs”). In making these evaluations, management considers a) the sufficiency of the investment’s equity at risk, b) the existence of a controlling financial interest, and c) the structure of any voting rights. In addition, management considers the specific facts and circumstances of each investment in a VIE when determining whether the Company is the primary beneficiary. The factors that management takes into consideration include the purpose and design of the VIE, the key decisions that affect its economic performance, whether the parties to the arrangements are related parties or defacto agents of the Company, and whether the Company has the power to direct the activities that would most significantly affect the economic performance of the VIE. Management’s judgment is also required to determine whether the Company has the right to receive benefits or the obligation to absorb losses of the VIE. Based on the judgments made, the Company will consolidate the VIE if it determines that it is the primary beneficiary.
Estimated Useful Lives and Recoverability of Long-Lived Assets, Intangibles 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

Management Discussion & Analysis – APUC 2019 Annual Report | 53

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.
In 2019 and 2018, Management assessed qualitative and quantitative factors for each of the reporting units that were allocated goodwill. No goodwill impairment provision was required.
Valuation of Deferred Tax Assets
In assessing the realization of deferred tax assets, management 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.
Accounting for Rate Regulation
Accounting guidance for regulated operations provides that rate-regulated entities account for and report assets and liabilities consistent with the recovery of those incurred costs in rates if the rates established are designed to recover the costs of providing the regulated service and if the competitive environment makes it probable that such rates can be charged and collected. This accounting guidance is applied to the Regulated Services Group’s operations.
Certain expenses and revenues subject to utility regulation or rate determination normally reflected in income are deferred on the balance sheet as regulatory assets or liabilities and are recognized in income as the related amounts are included in service rates and recovered from or refunded to customers. Regulatory assets and liabilities are recorded when it is probable that these items will be recovered or reflected in future rates. Determining probability requires significant judgment on the part of management and includes, but is not limited to, consideration of testimony presented in regulatory hearings, proposed regulatory decisions, final regulatory orders and industry practice. If events were to occur that would make the recovery of these assets and liabilities no longer probable, these regulatory assets and liabilities would be required to be written off or written down.
Unbilled Energy Revenues
Revenues related to natural gas, electricity and water delivery are generally recognized upon delivery to customers. The determination of customer billings is based on a systematic reading of meters throughout the month. At the end of each month, amounts of natural gas, energy or water provided to customers since the date of the last meter reading are estimated, and the corresponding unbilled revenue is recorded. Factors that can impact the estimate of unbilled energy include, but are not limited to, seasonal weather patterns compared to normal, total volumes supplied to the system, line losses, economic impacts, and composition of customer classes. Estimates are reversed in the following month and actual revenue is recorded based on subsequent meter readings.
Derivatives
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

Management Discussion & Analysis – APUC 2019 Annual Report | 54

the new mortality improvement scale (MP-2019) recently released by the Society of Actuaries adjusted to reflect the 2019 Social Security Administration ultimate improvement rates.
Sensitivities
The sensitivities of key assumptions used in measuring accrued benefit obligations and benefit plan cost for 2019 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.

| 2019 Pension Plans |  | 2019 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 | (54.7 | ) | (2.8 | ) |  | (32.4 | ) | (1.6 | )
1% decrease | 67.6 |  | 5.2 |  |  | 42.0 |  | 2.8 |
Future compensation rate |  |  |  |  |
1% increase | 0.3 |  | 1.8 |  |  | — |  | — |
1% decrease | (0.3 | ) | (3.1 | ) |  | — |  | — |
Expected return on plan assets |  |  |  |  |
1% increase | — |  | (3.3 | ) |  | — |  | (1.2 | )
1% decrease | — |  | 3.3 |  |  | — |  | 1.2 |
Life expectancy |  |  |  |  |
10% increase | 32.8 |  | 3.6 |  |  | 20.3 |  | 2.4 |
10% decrease | (34.4 | ) | (4.3 | ) |  | (19.4 | ) | (2.0 | )
Health care trend |  |  |  |  |
1% increase | — |  | — |  |  | 39.2 |  | 4.4 |
1% decrease | — |  | — |  |  | (30.8 | ) | (2.6 | )

Business Combinations
The Company has completed a number of business combinations in the past few years. Management’s judgment is required to estimate the purchase price, to identify and to fair value all assets and liabilities acquired. The determination of the fair value of assets and liabilities acquired is based upon management’s estimates and certain assumptions generally included in a present value calculation of the related cash flows.
Acquired assets and liabilities assumed that are subject to critical estimates include 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, on EDGAR at www.sec.gov/edgar, and on the APUC website at www.AlgonquinPowerandUtilities.com.

Management Discussion & Analysis – APUC 2019 Annual Report | 55

MANAGEMENT’S REPORT
Financial Reporting
The preparation and presentation of the accompanying consolidated financial statements, MD&A and all financial information in the consolidated financial statements are the responsibility of management and have been approved by the Board of Directors. The consolidated financial statements have been prepared in accordance with U.S. generally accepted accounting principles. Financial statements by nature include amounts based upon estimates and judgments. When alternative accounting methods exist, management has chosen those it deems most appropriate in the circumstances. Management has prepared the financial information presented elsewhere in this document and has ensured that it is consistent with that in the consolidated financial statements.
The Board of Directors and its committees are responsible for all aspects related to governance of the Company. The Audit Committee of the Board of Directors, composed of directors who are unrelated and independent, has a specific responsibility to oversee management’s efforts to fulfill its responsibilities for financial reporting and internal controls related thereto. The Committee meets with management and independent auditors to review the consolidated financial statements and the internal controls as they relate to financial reporting. The Audit Committee reports its findings to the Board of Directors for its consideration in approving the consolidated financial statements for issuance to the shareholders.
Internal Control over Financial Reporting
Management is also responsible for establishing and maintaining adequate internal control over financial reporting. The Company’s internal control over financial reporting is a process designed to provide reasonable assurance regarding the reliability of financial reporting and the preparation of consolidated financial statements for external purposes in accordance with generally accepted accounting principles.
During the year ended December 31, 2019, the Company acquired Enbridge Gas New Brunswick Limited Partnership (“New Brunswick Gas”) and St. Lawrence Gas Company, Inc. (“St. Lawrence Gas”). Management is in the process of evaluating the existing controls and procedures of New Brunswick Gas and St. Lawrence Gas and integrating financial reporting and controls for New Brunswick Gas and St. Lawrence gas into the Company’s internal control over financial reporting. The financial information for these acquisitions is included in this MD&A and in note 3 to the consolidated financial statements. As permitted by National Instrument 52-109 and the U.S. Securities and Exchange Commission, due to the complexity associated with assessing internal controls during integration efforts, the Company excluded these acquisitions from its evaluation of the effectiveness of the Company’s internal controls over financial reporting as of December 31, 2019 (representing approximately 4% of its total assets as of December 31, 2019 and approximately 2% of its revenues for the year ended December 31, 2019).
Management assessed the effectiveness of the Company’s internal control over financial reporting as of December 31, 2019, based on the framework established in Internal Control – Integrated Framework (2013) issued by the Committee of Sponsoring Organizations of the Treadway Commission (COSO). Based on this assessment, management concluded that the Company maintained effective internal control over financial reporting as of December 31, 2019.
February 27, 2020

/s/ Ian Robertson |  | /s/ David Bronicheski
Chief Executive Officer |  | Chief Financial Officer

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REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM
To the Shareholders and Directors of
Algonquin Power & Utilities Corp.
Opinion on the Consolidated Financial Statements
We have audited the accompanying consolidated balance sheets of Algonquin Power & Utilities Corp. [the “Company”], as of December 31, 2019 and 2018, the related consolidated statements of operations, comprehensive income, equity and cash flows for the years then ended, and the related notes [collectively referred to as the “consolidated financial statements”]. In our opinion, the consolidated financial statements present fairly, in all material respects, the financial position of the Company as of December 31, 2019 and 2018, and the results of its operations and its cash flows for the years then ended in conformity with U.S. generally accepted accounting principles.
Report on Internal Control over Financial Reporting
We also have audited, in accordance with the standards of the Public Company Accounting Oversight Board (United States) [“PCAOB”], the Company’s internal control over financial reporting as of December 31, 2019, based on the criteria established in Internal Control - Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission (2013 framework), and our report dated February 27, 2020 expressed an unqualified opinion thereon.
Basis for Opinion
These consolidated financial statements are the responsibility of the Company’s management. Our responsibility is to express an opinion on the Company’s consolidated financial statements based on our audits. We are a public accounting firm registered with the PCAOB and are required to be independent with respect to the Company in accordance with the US federal securities laws and the applicable rules and regulations of the Securities and Exchange Commission and the PCAOB.
We conducted our audits in accordance with the standards of the PCAOB. Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the consolidated financial statements are free of material misstatement, whether due to error or fraud. Our audits included performing procedures to assess the risks of material misstatement of the consolidated financial statements, whether due to error or fraud, and performing procedures that respond to those risks. Such procedures include examining, on a test basis, evidence regarding the amounts and disclosures in the consolidated financial statements. Our audits also included evaluating the accounting principles used and significant estimates made by management, as well as evaluating the overall presentation of the consolidated financial statements. We believe that our audits provide a reasonable basis for our opinion.
Critical Audit Matter
The critical audit matter communicated below is a matter arising from the current period audit of the consolidated financial statements that was communicated or required to be communicated to the audit committee and that: (1) relates to accounts or disclosures that are material to the consolidated financial statements and (2) involved our especially challenging, subjective or complex judgments. The communication of the critical audit matter does not alter in any way our opinion on the consolidated financial statements, taken as a whole, and we are not, by communicating the critical audit matter below, providing a separate opinion on the critical audit matter or on the accounts or disclosures to which it relates.

Independent Auditor’s Report – APUC 2019 Annual Report | 57

| Accounting for Long-term Investments and Related Financing Arrangements
Description of the Matter | As more fully described in Notes 8 and 17 to the consolidated financial statements, the Company has various long-term investments and related financing arrangements with Atlantica Yield PLC, Abengoa-Algonquin Global Energy Solutions B.V. and other entities. In the current year, the Company also entered into various new long-term investments including Atlantica Yield Energy Solutions Canada Inc., a subsidiary of Atlantica Yield PLC, and AAGES Sugar Creek, amongst others.
| The accounting for these investments involves the application of the variable interest model, which includes evaluating whether various entities within these investment structures are variable interest entities (“VIE”) and whether the Company is the primary beneficiary of the VIE. If the Company is the primary beneficiary of the VIE, then the VIE is consolidated. These assessments are complex and required significant judgment. Such judgments include a consideration of the adequacy of equity at risk within the entities, consideration of whether other parties to the arrangements are agents or defacto agents and determining the party that has the power to direct the activities of the entities that most significantly affect their economic performance and evaluating the debt and equity characteristics of certain financing instruments. In addition, certain financing arrangements entered into as part of the funding of these investment structures required consideration of whether the financing arrangements are debt or non-controlling interests.
| The Company also monitors for reconsideration events relating to these investment structures which necessitates on-going critical judgments over whether any such events have arisen that require a re-evaluation of prior accounting judgments.
How We Addressed the Matter in Our Audit | We obtained an understanding, evaluated the design and tested the operating effectiveness of controls over the Company’s application of the variable interest model, including the process of evaluating whether an entity is a VIE, whether the Company is the primary beneficiary of the VIE, the classification of related financing instruments and the assessment of reconsideration events.
| To evaluate the Company’s conclusions about the determination of variable interest entities and consolidation, our audit procedures included, amongst others, obtaining and reviewing all agreements associated with the set-up or acquisition of the respective investments, investee financial information and other legal documents. We reviewed management’s analysis of the significant activities and evaluated which party has the power to direct such activities, considering the purpose and design of the entity, composition of the board of directors and other legal rights of the parties, including whether there were indicators that other parties to the arrangement were acting in the role of agents or defacto agents. We also compared the rights of each party to underlying legal documents, articles of incorporation and board of directors’ minutes. In addition, we performed an evaluation of the various entities’ equity and whether such equity at risk was sufficient to conduct its related activities. We analyzed the at-risk equity holder’s obligation to absorb the investments’ expected losses and right to receive expected residual returns.

Independent Auditor’s Report – APUC 2019 Annual Report | 58

| We further evaluated the accounting and presentation of related financing instruments by reviewing the agreements and terms related to such instruments and assessing their equity and debt characteristics.
| Finally, we inspected new financing arrangements and any changes to related agreements within the respective structures to determine if a reconsideration event arose that necessitated a re-evaluation of previous accounting judgments.

/s/ Ernst & Young LLP |  |
Chartered Professional Accountants |  |
Licensed Public Accountants |  |
We have served as the Company’s auditor since 2013. |  |
Toronto, Canada |  |
February 27, 2020 |  |

Independent Auditor’s Report – APUC 2019 Annual Report | 59

REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM
To the Shareholders and Directors of
Algonquin Power & Utilities Corp.
Opinion on Internal Control over Financial Reporting
We have audited Algonquin Power & Utilities Corp.’s internal control over financial reporting as of December 31, 2019, based on criteria established in Internal Control—Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission [2013 framework] [the “COSO criteria”]. In our opinion, Algonquin Power & Utilities Corp. [the “Company”] maintained, in all material respects, effective internal control over financial reporting as of December 31, 2019, based on the COSO criteria.
As indicated in the accompanying Internal Controls over Financial Reporting section in Management’s Report, management’s assessment of and conclusion on the effectiveness of internal control over financial reporting did not include the internal controls of Enbridge Gas New Brunswick Limited Partnership [“New Brunswick Gas”] and St. Lawrence Gas Company, Inc. [“St. Lawrence Gas”], which are included in the 2019 consolidated financial statements of the Company and constituted 4% of total assets as of December 31, 2019 and 2% of revenues for the year then ended. Our audit of internal control over financial reporting of the Company also did not include an evaluation of the internal control over financial reporting of New Brunswick Gas and St. Lawrence Gas.
We also have audited, in accordance with the standards of the Public Accounting Oversight Board (United States) [“PCAOB”], the consolidated balance sheets as of December 31, 2019 and 2018, and the consolidated statements of operations, comprehensive income, equity and cash flows for the years then ended, and the related notes, and our report dated February 27, 2020 expressed an unqualified opinion thereon.
Basis for Opinion
The Company’s management is responsible for maintaining effective internal control over financial reporting and for its assessment of the effectiveness of internal control over financial reporting included in the accompanying Management’s Report. Our responsibility is to express an opinion on the Company’s internal control over financial reporting based on our audit. We are a public accounting firm registered with the PCAOB and are required to be independent with respect to the Company in accordance with the U.S. federal securities laws and the applicable rules and regulations of the Securities and Exchange Commission and the PCAOB.
We conducted our audit in accordance with the standards of the PCAOB. Those standards require that we plan and perform the audit to obtain reasonable assurance about whether effective internal control over financial reporting was maintained in all material respects.
Our audit included obtaining an understanding of internal control over financial reporting, assessing the risk that a material weakness exists, testing and evaluating the design and operating effectiveness of internal control based on the assessed risk, and performing such other procedures as we considered necessary in the circumstances. We believe that our audit provides a reasonable basis for our opinion.

Independent Auditor’s Report – APUC 2019 Annual Report | 60

Definition and Limitations of Internal Control Over Financial Reporting
A company’s internal control over financial reporting is a process designed to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles. A company’s internal control over financial reporting includes those policies and procedures that (1) pertain to the maintenance of records that, in reasonable detail, accurately and fairly reflect the transactions and dispositions of the assets of the company; (2) provide reasonable assurance that transactions are recorded as necessary to permit preparation of financial statements in accordance with generally accepted accounting principles, and that receipts and expenditures of the company are being made only in accordance with authorizations of management and directors of the company; and (3) provide reasonable assurance regarding prevention or timely detection of unauthorized acquisition, use, or disposition of the company’s assets that could have a material effect on the financial statements.
Because of its inherent limitations, internal control over financial reporting may not prevent or detect misstatements. Also, projections of any evaluation of effectiveness to future periods are subject to the risk that controls may become inadequate because of changes in conditions, or that the degree of compliance with the policies or procedures may deteriorate.

/s/ Ernst & Young LLP |  |
Chartered Professional Accountants |  |
Licensed Public Accountants |  |
Toronto, Canada |  |
February 27, 2020 |  |

Independent Auditor’s Report – APUC 2019 Annual Report | 61

Algonquin Power & Utilities Corp.
Consolidated Statements of Operations

(thousands of U.S. dollars, except per share amounts) | Year ended December 31
| 2019 |  | 2018
Revenue |  |  |
Regulated electricity distribution | $ | 784,396 |  |  | $ | 831,196 |
Regulated gas distribution | 439,153 |  |  | 431,453 |
Regulated water reclamation and distribution | 130,488 |  |  | 128,437 |
Non-regulated energy sales | 246,601 |  |  | 235,359 |
Other revenue | 24,283 |  |  | 22,018 |
| 1,624,921 |  |  | 1,648,463 |
Expenses |  |  |
Operating expenses | 471,989 |  |  | 472,466 |
Regulated electricity purchased | 247,417 |  |  | 265,166 |
Regulated gas purchased | 170,487 |  |  | 183,012 |
Regulated water purchased | 8,142 |  |  | 8,796 |
Non-regulated energy purchased | 17,258 |  |  | 27,164 |
Administrative expenses | 56,802 |  |  | 52,710 |
Depreciation and amortization | 284,304 |  |  | 260,772 |
Loss (gain) on foreign exchange | 3,146 |  |  | (58 | )
| 1,259,545 |  |  | 1,270,028 |
Operating income | 365,376 |  |  | 378,435 |
Interest expense on long-term debt and others | (181,488 | ) |  | (152,118 | )
Income (loss) from long-term investments (note 8) | 399,092 |  |  | (84,818 | )
Other net losses (note 19) | (44,026 | ) |  | (8,402 | )
Gain (loss) on derivative financial instruments (note 24(b)(iv)) | 16,113 |  |  | (636 | )
| 189,691 |  |  | (245,974 | )
Earnings before income taxes | 555,067 |  |  | 132,461 |
Income tax expense (note 18) |  |  |
Current | (16,431 | ) |  | (11,347 | )
Deferred | (53,686 | ) |  | (42,025 | )
| (70,117 | ) |  | (53,372 | )
Net earnings | 484,950 |  |  | 79,089 |
Net effect of non-controlling interests (note 17) |  |  |
Net effect of non-controlling interests | 62,416 |  |  | 108,521 |
Net effect of non-controlling interests held by related party | (16,482 | ) |  | (2,622 | )
| $ | 45,934 |  |  | $ | 105,899 |
Net earnings attributable to shareholders of Algonquin Power & Utilities Corp. | $ | 530,884 |  |  | $ | 184,988 |
Series A and D Preferred shares dividend (note 15) | 8,486 |  |  | 8,027 |
Net earnings attributable to common shareholders of Algonquin Power & Utilities Corp. | $ | 522,398 |  |  | $ | 176,961 |
Basic net earnings per share (note 20) | $ | 1.05 |  |  | $ | 0.38 |
Diluted net earnings per share (note 20) | $ | 1.04 |  |  | $ | 0.38 |

See accompanying notes to consolidated financial statements

Consolidated Financial Statements – APUC 2019 Annual Report | 62

Algonquin Power & Utilities Corp.
Consolidated Statements of Comprehensive Income

(thousands of U.S. dollars) | Year ended December 31
| 2019 |  | 2018
Net earnings | $ | 484,950 |  |  | $ | 79,089 |
Other comprehensive income (loss): |  |  |
Foreign currency translation adjustment, net of tax recovery of $289 and $4,532, respectively (notes 1(u), 24(b)(iii) and 24(b)(iv)) | 7,795 |  |  | (27,969 | )
Change in fair value of cash flow hedges, net of tax expense and tax recovery of $3,862 and $952, respectively (note 24(b)(ii)) | 10,580 |  |  | (2,690 | )
Change in pension and other post-employment benefits, net of tax recovery and tax expense of $2,735 and $696, respectively (note 10) | (6,509 | ) |  | 1,960 |
Other comprehensive income (loss), net of tax | 11,866 |  |  | (28,699 | )
Comprehensive income | 496,816 |  |  | 50,390 |
Comprehensive loss attributable to the non-controlling interests | (43,506 | ) |  | (107,380 | )
Comprehensive income attributable to shareholders of Algonquin Power & Utilities Corp. | $ | 540,322 |  |  | $ | 157,770 |

See accompanying notes to consolidated financial statements

Consolidated Financial Statements – APUC 2019 Annual Report | 63

Algonquin Power & Utilities Corp.
Consolidated Balance Sheets

(thousands of U.S. dollars) |  |  |
| December 31, 2019 |  | December 31, 2018
ASSETS |  |  |
Current assets: |  |  |
Cash and cash equivalents | $ | 62,485 |  |  | $ | 46,819 |
Accounts receivable, net (note 4) | 259,144 |  |  | 245,728 |
Fuel and natural gas in storage | 30,804 |  |  | 43,063 |
Supplies and consumables inventory | 60,295 |  |  | 52,537 |
Regulatory assets (note 7) | 50,213 |  |  | 59,037 |
Prepaid expenses | 29,003 |  |  | 27,283 |
Derivative instruments (note 24) | 13,483 |  |  | 9,616 |
Other assets and long-term investments (notes 8 and 11) | 7,764 |  |  | 7,522 |
| 513,191 |  |  | 491,605 |
Property, plant and equipment, net (note 5) | 7,231,664 |  |  | 6,393,558 |
Intangible assets, net (note 6) | 47,616 |  |  | 54,994 |
Goodwill (note 6) | 1,031,696 |  |  | 954,282 |
Regulatory assets (note 7) | 509,674 |  |  | 401,058 |
Long-term investments (note 8) |  |  |
Investments carried at fair value | 1,294,147 |  |  | 814,530 |
Other long-term investments | 121,968 |  |  | 134,371 |
Derivative instruments (note 24) | 72,221 |  |  | 53,192 |
Deferred income taxes (note 18) | 30,585 |  |  | 72,415 |
Other assets (note 11) | 58,708 |  |  | 28,584 |
| $ | 10,911,470 |  |  | $ | 9,398,589 |

See accompanying notes to consolidated financial statements

Consolidated Financial Statements – APUC 2019 Annual Report | 64

Algonquin Power & Utilities Corp.
Consolidated Balance Sheets

(thousands of U.S. dollars) |  |  |
| December 31, 2019 |  | December 31, 2018
LIABILITIES AND EQUITY |  |  |
Current liabilities: |  |  |
Accounts payable | $ | 150,336 |  |  | $ | 89,740 |
Accrued liabilities | 307,952 |  |  | 235,586 |
Dividends payable (note 15) | 73,945 |  |  | 62,613 |
Regulatory liabilities (note 7) | 41,683 |  |  | 39,005 |
Long-term debt (note 9) | 225,013 |  |  | 13,048 |
Other long-term liabilities (note 12) | 57,939 |  |  | 42,337 |
Derivative instruments (note 24) | 5,898 |  |  | 14,339 |
Other liabilities | 9,300 |  |  | 2,313 |
| 872,066 |  |  | 498,981 |
Long-term debt (note 9) | 3,706,855 |  |  | 3,323,747 |
Regulatory liabilities (note 7) | 556,379 |  |  | 549,208 |
Deferred income taxes (note 18) | 491,538 |  |  | 444,145 |
Derivative instruments (note 24) | 78,766 |  |  | 88,503 |
Pension and other post-employment benefits obligation (note 10) | 224,094 |  |  | 199,829 |
Other long-term liabilities (note 12) | 243,401 |  |  | 255,668 |
| 5,301,033 |  |  | 4,861,100 |
Redeemable non-controlling interests (note 17) |  |  |
Redeemable non-controlling interest, held by related party (note 16(b)) | 305,863 |  |  | 307,622 |
Redeemable non-controlling interests | 25,913 |  |  | 33,364 |
Equity: |  |  |
Preferred shares (note 13(b)) | 184,299 |  |  | 184,299 |
Common shares (note 13(a)) | 4,017,044 |  |  | 3,562,418 |
Additional paid-in capital | 50,579 |  |  | 45,553 |
Deficit | (367,107 | ) |  | (595,259 | )
Accumulated other comprehensive loss (note 14) | (9,761 | ) |  | (19,385 | )
Total equity attributable to shareholders of Algonquin Power & Utilities Corp. | 3,875,054 |  |  | 3,177,626 |
Non-controlling interests (note 17) |  |  |
Non-controlling interests | 457,834 |  |  | 519,896 |
Non-controlling interest, held by related party (note 16(c)) | 73,707 |  |  | — |
| 531,541 |  |  | 519,896 |
Total equity | 4,406,595 |  |  | 3,697,522 |
Commitments and contingencies (note 22) |  |  |
Subsequent events (notes 1(u), 8(a), 9(a), 9(d), 13(a)(iii)) and 24(b)(ii)) |  |  |
| $ | 10,911,470 |  |  | $ | 9,398,589 |

See accompanying notes to consolidated financial statements

Consolidated Financial Statements – APUC 2019 Annual Report | 65

Algonquin Power & Utilities Corp.
Consolidated Statement of Equity

(thousands of U.S. dollars) For the year ended December 31, 2019 |  |  |  |  |  |  |  |  |  |
| Algonquin Power & Utilities Corp. Shareholders |  |  |  |
| Common shares |  | Preferred shares |  | Additional paid-in capital |  | Accumulated deficit |  | Accumulated OCI |  | Non- controlling interests |  | Total
Balance, December 31, 2018 | $ | 3,562,418 |  |  | $ | 184,299 |  |  | $ | 45,553 |  |  | $ | (595,259 | ) |  | $ | (19,385 | ) |  | $ | 519,896 |  |  | $ | 3,697,522 |
Adoption of ASU 2017-12 on hedging (note 2(a)) | — |  |  | — |  |  | — |  |  | (186 | ) |  | 186 |  |  | — |  |  | — |
Net earnings (loss) | — |  |  | — |  |  | — |  |  | 530,884 |  |  | — |  |  | (45,934 | ) |  | 484,950 |
Redeemable non-controlling interests not included in equity (note 17) | — |  |  | — |  |  | — |  |  | — |  |  | — |  |  | (7,476 | ) |  | (7,476 | )
Other comprehensive income | — |  |  | — |  |  | — |  |  | — |  |  | 9,438 |  |  | 2,428 |  |  | 11,866 |
Dividends declared and distributions to non-controlling interests | — |  |  | — |  |  | — |  |  | (217,464 | ) |  | — |  |  | (37,691 | ) |  | (255,155 | )
Dividends and issuance of shares under dividend reinvestment plan (note 13(a)(iii)) | 68,856 |  |  | — |  |  | — |  |  | (68,856 | ) |  | — |  |  | — |  |  | — |
Contributions received from non-controlling interests | — |  |  | — |  |  | — |  |  | — |  |  | — |  |  | 100,318 |  |  | 100,318 |
Common shares issued upon conversion of convertible debentures | 148 |  |  | — |  |  | — |  |  | — |  |  | — |  |  | — |  |  | 148 |
Common shares issued upon public offering, net of cost | 364,211 |  |  | — |  |  | — |  |  | — |  |  | — |  |  | — |  |  | 364,211 |
Issuance of common shares under employee share purchase plan | 2,853 |  |  | — |  |  | — |  |  | — |  |  | — |  |  | — |  |  | 2,853 |
Share-based compensation | — |  |  | — |  |  | 12,974 |  |  | — |  |  | — |  |  | — |  |  | 12,974 |
Common shares issued pursuant to share-based awards | 18,558 |  |  | — |  |  | (7,948 | ) |  | (16,226 | ) |  | — |  |  | — |  |  | (5,616 | )
Balance, December 31, 2019 | $ | 4,017,044 |  |  | $ | 184,299 |  |  | $ | 50,579 |  |  | $ | (367,107 | ) |  | $ | (9,761 | ) |  | $ | 531,541 |  |  | $ | 4,406,595 |

See accompanying notes to consolidated financial statements

Consolidated Financial Statements – APUC 2019 Annual Report | 66

Algonquin Power & Utilities Corp.
Consolidated Statement of Equity

(thousands of U.S. dollars) For the year ended December 31, 2018 |  |  |  |  |  |  |  |  |  |
| Algonquin Power & Utilities Corp. Shareholders |  |  |  |
| Common shares |  | Preferred shares |  | Additional paid-in capital |  | Accumulated deficit |  | Accumulated OCI |  | Non- controlling interests |  | Total
Balance, December 31, 2017 | $ | 3,021,699 |  |  | $ | 184,299 |  |  | $ | 38,569 |  |  | $ | (524,311 | ) |  | $ | (2,792 | ) |  | $ | 602,636 |  |  | $ | 3,320,100 |
Adoption of Topic 606 on revenue (note 1(t)) | — |  |  | — |  |  | — |  |  | 1,860 |  |  | — |  |  | — |  |  | 1,860 |
Adoption of ASU 2018-02 on tax effects in AOCI | — |  |  | — |  |  | — |  |  | (10,625 | ) |  | 10,625 |  |  | — |  |  | — |
Net earnings (loss) | — |  |  | — |  |  | — |  |  | 184,988 |  |  | — |  |  | (105,899 | ) |  | 79,089 |
Redeemable non-controlling interests not included in equity (note 17) | — |  |  | — |  |  | — |  |  | — |  |  | — |  |  | 4,923 |  |  | 4,923 |
Other comprehensive loss | — |  |  | — |  |  | — |  |  | — |  |  | (27,218 | ) |  | (1,481 | ) |  | (28,699 | )
Dividends declared and distributions to non-controlling interests | — |  |  | — |  |  | — |  |  | (187,890 | ) |  | — |  |  | (9,393 | ) |  | (197,283 | )
Dividends and issuance of shares under dividend reinvestment plan (note 13(a)(iii)) | 55,442 |  |  | — |  |  | — |  |  | (55,442 | ) |  | — |  |  | — |  |  | — |
Common shares issued pursuant to public offering, net of costs (note 13(a)(i)) | 472,180 |  |  | — |  |  | — |  |  | — |  |  | — |  |  | — |  |  | 472,180 |
Common shares issued upon conversion of convertible debentures (note 12(h)) | 447 |  |  | — |  |  | — |  |  | — |  |  | — |  |  | — |  |  | 447 |
Common shares issued pursuant to share-based awards (note 13(c)) | 12,650 |  |  | — |  |  | (4,027 | ) |  | (3,839 | ) |  | — |  |  | — |  |  | 4,784 |
Share-based compensation (note 13(c)) | — |  |  | — |  |  | 11,011 |  |  | — |  |  | — |  |  | — |  |  | 11,011 |
Contributions received from non-controlling interests (note 3(g)), net of costs | — |  |  | — |  |  | — |  |  | — |  |  | — |  |  | 29,110 |  |  | 29,110 |
Balance, December 31, 2018 | $ | 3,562,418 |  |  | $ | 184,299 |  |  | $ | 45,553 |  |  | $ | (595,259 | ) |  | $ | (19,385 | ) |  | $ | 519,896 |  |  | $ | 3,697,522 |

See accompanying notes to consolidated financial statements

Consolidated Financial Statements – APUC 2019 Annual Report | 67

Algonquin Power & Utilities Corp.
Consolidated Statements of Cash Flows

(thousands of U.S. dollars) | Year ended December 31
| 2019 |  | 2018
Cash provided by (used in): |  |  |
Operating Activities |  |  |
Net earnings | $ | 484,950 |  |  | $ | 79,089 |
Adjustments and items not affecting cash: |  |  |
Depreciation and amortization | 284,304 |  |  | 260,772 |
Deferred taxes | 53,686 |  |  | 42,025 |
Unrealized gain on derivative financial instruments | (15,237 | ) |  | (1,781 | )
Share-based compensation expense | 11,042 |  |  | 7,495 |
Cost of equity funds used for construction purposes | (4,896 | ) |  | (2,728 | )
Change in value of investments carried at fair value | (276,458 | ) |  | 137,957 |
Pension and post-employment contributions in excess of expense | (8,952 | ) |  | (6,354 | )
Distributions received from equity investments, net of income | 7,487 |  |  | 5,698 |
Others | 15,031 |  |  | 16,305 |
Changes in non-cash operating items (note 23) | 60,303 |  |  | (8,126 | )
| 611,260 |  |  | 530,352 |
Financing Activities |  |  |
Increase in long-term debt | 3,614,758 |  |  | 2,015,533 |
Decrease in long-term debt | (3,048,008 | ) |  | (1,699,592 | )
Issuance of common shares, net of costs | 362,364 |  |  | 473,911 |
Cash dividends on common shares | (196,391 | ) |  | (166,384 | )
Dividends on preferred shares | (8,486 | ) |  | (8,027 | )
Contributions from non-controlling interests, related party (note 17) | 96,752 |  |  | 305,000 |
Contributions from non-controlling interests and redeemable non-controlling interests (note 17) | 3,403 |  |  | 15,250 |
Production-based cash contributions from non-controlling interest | 3,565 |  |  | 13,860 |
Distributions to non-controlling interests, related party (note 16(b) and (c)) | (38,718 | ) |  | — |
Distributions to non-controlling interests | (12,251 | ) |  | (9,289 | )
Settlement of derivatives | (8,732 | ) |  | — |
Proceeds from exercise of share options | — |  |  | 4,504 |
Shares surrendered to fund withholding taxes on exercised share options | (5,282 | ) |  | (2,088 | )
Increase in other long-term liabilities | 10,175 |  |  | 9,403 |
Decrease in other long-term liabilities | (39,783 | ) |  | (20,144 | )
| 733,366 |  |  | 931,937 |
Investing Activities |  |  |
Additions to property, plant and equipment and intangible assets | (581,332 | ) |  | (466,369 | )
Increase in long-term investments | (669,832 | ) |  | (1,005,072 | )
Acquisitions of operating entities | (308,423 | ) |  | — |
Increase in other assets | (16,690 | ) |  | (5,912 | )
Receipt of principal on development loans receivable | 251,118 |  |  | 17,950 |
Decrease in long-term investments | 1,000 |  |  | 1,158 |
Proceeds from sale of long-lived assets | — |  |  | 2,912 |
| (1,324,159 | ) |  | (1,455,333 | )
Effect of exchange rate differences on cash and restricted cash | 1,032 |  |  | (606 | )
Increase in cash, cash equivalents and restricted cash | 21,499 |  |  | 6,350 |
Cash, cash equivalents and restricted cash, beginning of year | 65,773 |  |  | 59,423 |
Cash, cash equivalents and restricted cash, end of year | $ | 87,272 |  |  | $ | 65,773 |
Supplemental disclosure of cash flow information: | 2019 |  | 2018
Cash paid during the year for interest expense | $ | 171,548 |  |  | $ | 155,309 |
Cash paid during the year for income taxes | $ | 14,543 |  |  | $ | 9,652 |
Non-cash financing and investing activities: |  |  |
Property, plant and equipment acquisitions in accruals | $ | 98,231 |  |  | $ | 45,154 |
Issuance of common shares under dividend reinvestment plan and share-based compensation plans | $ | 87,414 |  |  | $ | 65,767 |
Issuance of common shares upon conversion of convertible debentures | $ | 155 |  |  | $ | 468 |
Sale of property, plant and equipment, intangible assets and accrued liabilities in exchange of note receivable | $ | 57,753 |  |  | $ | 13,092 |

See accompanying notes to consolidated financial statements

Consolidated Financial Statements – APUC 2019 Annual Report | 68

Algonquin Power & Utilities Corp.
Notes to the Consolidated Financial Statements
December 31, 2019 and 2018
(in thousands of U.S. dollars, except as noted and per share amounts)

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

1. | Significant accounting policies

(a) | Basis of preparation

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

(b) | Basis of consolidation

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

(c) | Business combinations, intangible assets and goodwill

The Company accounts for acquisitions of entities or assets that meet the definition of a business as business combinations. Business combinations are accounted for using the acquisition method. Assets acquired and liabilities assumed are measured at their fair value at the acquisition date, except for deferred income taxes which are accounted for as described in note 1(v). Acquisition costs are expensed in the period incurred. When the set of activities does not represent a business, the transaction is accounted for as an asset acquisition and includes acquisition costs.
Intangible assets acquired are recognized separately at fair value if they arise from contractual or other legal rights or are separable. Power sales contracts are amortized on a straight-line basis over the remaining term of the contract ranging from 6 to 25 years from the date of acquisition. Interconnection agreements are amortized on a straight-line basis over their estimated life of 40 years. Customer relationships are amortized on a straight-line basis over their estimated life of 40 years.
Goodwill represents the excess of the purchase price of an acquired business over the fair value of the net assets acquired. Goodwill is generally not included in the rate base on which regulated utilities are allowed to earn a return and is not amortized.
As at September 30 of each year, the Company assesses qualitative and quantitative factors to determine whether it is more likely than not that the fair value of a reporting unit to which goodwill is attributed is less than its carrying amount. If it is more likely than not that a reporting unit’s fair value is less than its carrying amount or if a quantitative assessment is elected, the Company calculates the fair value of the reporting unit. The carrying amount of the reporting unit’s goodwill is considered not recoverable if the carrying amount of the reporting unit as a whole exceeds the reporting unit’s fair value. An impairment charge is recorded for any excess of the carrying value of the goodwill over the implied fair value. Goodwill is tested for impairment between annual tests if an event occurs or circumstances change that would more likely than not reduce the fair value of a reporting unit below its carrying amount.

(d) | Accounting for rate regulated operations

The operating companies within the Regulated Services Group are subject to rate regulation generally overseen by the public utility commission of the states and provinces in which they operate (the “Regulator”). The Regulator provides the final determination of the rates charged to customers. APUC’s regulated operating companies are accounted for under the principles of U.S. Financial Accounting Standards Board (“FASB”) ASC Topic 980, Regulated Operations (“ASC 980”).

Notes to the Consolidated Financial Statements – APUC 2019 Annual Report | 69

Algonquin Power & Utilities Corp.
Notes to the Consolidated Financial Statements
December 31, 2019 and 2018
(in thousands of U.S. dollars, except as noted and per share amounts)

1. | Significant accounting policies (continued)

(d) | Accounting for rate regulated operations (continued)

Under ASC 980, regulatory assets and liabilities are recorded to the extent that they represent probable future revenue or expenses associated with certain charges or credits that will be recovered from or refunded to customers through the rate making process. Included in note 7 “Regulatory matters” are details of regulatory assets and liabilities, and their current regulatory treatment.
In the event the Company determines that its net regulatory assets are not probable of recovery, it would no longer apply the principles of the current accounting guidance for rate regulated enterprises and would be required to record an after-tax, non-cash charge or credit against earnings for any remaining regulatory assets or liabilities. The impact could be material to the Company’s reported financial condition and results of operations.
The U.S. electric, gas and water utilities’ accounts are maintained in accordance with the Uniform System of Accounts prescribed by the Federal Energy Regulatory Commission (“FERC”), the Regulator and National Association of Regulatory Utility Commissioners in the United States. The New Brunswick Gas accounts are maintained in accordance with the New Brunswick Gas Distribution Act Uniform Accounting Regulation.

(e) | Cash and cash equivalents

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

(f) | Restricted cash

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

(g) | Accounts receivable

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

(h) | Fuel and natural gas in storage

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

(i) | Supplies and consumables inventory

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

Notes to the Consolidated Financial Statements – APUC 2019 Annual Report | 70

Algonquin Power & Utilities Corp.
Notes to the Consolidated Financial Statements
December 31, 2019 and 2018
(in thousands of U.S. dollars, except as noted and per share amounts)

1. | Significant accounting policies (continued)

(j) Property, plant and equipment
Property, plant and equipment are recorded at cost. Capitalization of development projects begins when management with the relevant authority has authorized and committed to the funding of a project and it is probable that costs will be realized through the use of the asset or ultimate construction and operation of a facility. Project development costs for rate regulated entities, including expenditures for preliminary surveys, plans, investigations, environmental studies, regulatory applications and other costs incurred for the purpose of determining the feasibility of capital expansion projects, are capitalized either as property, plant and equipment or regulatory assets when it is determined that recovery of such costs through regulated revenue of the completed project is probable.
The costs of acquiring or constructing property, plant and equipment include the following: materials, labour, contractor and professional services, construction overhead directly attributable to the capital project (where applicable), interest for non-regulated property and allowance for funds used during construction (“AFUDC”) for regulated property. Where possible, individual components are recorded and depreciated separately in the books and records of the Company. Plant and equipment under finance leases are initially recorded at cost determined as the present value of lease payments to be made over the lease term.
AFUDC represents the cost of borrowed funds and a return on other funds. Under ASC 980, an allowance for funds used during construction projects that are included in rate base is capitalized. This allowance is designed to enable a utility to capitalize financing costs during periods of construction of property subject to rate regulation. For operations that do not apply regulatory accounting, interest related only to debt is capitalized as a cost of construction in accordance with ASC 835, Interest. The interest capitalized that relates to debt reduces interest expense on the consolidated statements of operations. The AFUDC capitalized that relates to equity funds is recorded as interest and other income under income from long-term investments on the consolidated statements of operations.
Improvements that increase or prolong the service life or capacity of an asset are capitalized. Costs incurred for major expenditures or overhauls that occur at regular intervals over the life of an asset are capitalized and depreciated over the related interval. Maintenance and repair costs are expensed as incurred.
Grants related to capital expenditures are recorded as a reduction to the cost of assets and are amortized at the rate of the related asset as a reduction to depreciation expense. Grants related to operating expenses such as maintenance and repairs costs are recorded as a reduction of the related expense. Contributions in aid of construction represent amounts contributed by customers, governments and developers to assist with the funding of some or all of the cost of utility capital assets. It also includes amounts initially recorded as advances in aid of construction (note 12(a)) but where the advance repayment period has expired. These contributions are recorded as a reduction in the cost of utility assets and are amortized at the rate of the related asset as a reduction to depreciation expense.
The Company’s depreciation is based on the estimated useful lives of the depreciable assets in each category and is determined using the straight-line method with the exception of certain wind assets, as described below. The ranges of estimated useful lives and the weighted average useful lives are summarized below:

| Range of useful lives |  | Weighted average useful lives
| 2019 |  | 2018 |  | 2019 |  | 2018
Generation | 3 - 60 |  | 3 - 60 |  | 33 |  | 33
Distribution | 5 - 100 |  | 5 - 100 |  | 42 |  | 40
Equipment | 5 - 44 |  | 5 - 43 |  | 10 |  | 10

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

Notes to the Consolidated Financial Statements – APUC 2019 Annual Report | 71

Algonquin Power & Utilities Corp.
Notes to the Consolidated Financial Statements
December 31, 2019 and 2018
(in thousands of U.S. dollars, except as noted and per share amounts)

1. | Significant accounting policies (continued)

(j) Property, plant and equipment (continued)
In accordance with regulator-approved accounting policies, when depreciable property, plant and equipment of the Regulated Services Group are replaced or retired, the original cost plus any removal costs incurred (net of salvage) are charged to accumulated depreciation with no gain or loss reflected in results of operations. Gains and losses will be charged to results of operations in the future through adjustments to depreciation expense. In the absence of regulator-approved accounting policies, gains and losses on the disposition of property, plant and equipment are charged to earnings as incurred.
(k)Commonly owned facilities
The Regulated Services Group owns undivided interests in three electric generating facilities with ownership interest ranging from 7.52% to 60% with a corresponding share of capacity and generation from the facility used to serve certain of its utility customers. The Company’s investment in the undivided interest is recorded as plant in service and recovered through rate base. The Company’s share of operating costs is recognized in operating, maintenance and fuel expenditures excluding depreciation expense.

(l) | Impairment of long-lived assets

APUC reviews property, plant and equipment and intangible assets for impairment whenever events or changes in circumstances indicate the carrying amount may not be recoverable.
Recoverability of assets expected to be held and used is measured by comparing the carrying amount of an asset to undiscounted expected future cash flows. If the carrying amount exceeds the recoverable amount, the asset is written down to its fair value.

(m) | Variable interest entities

The Company performs analyses to assess whether its operations and investments represent VIEs. To identify potential VIEs, management reviews contracts under leases, long-term purchase power agreements and jointly owned facilities. VIEs for which the Company is deemed the primary beneficiary are consolidated. In circumstances where APUC is not deemed the primary beneficiary, the VIE is not consolidated (note 8).
The Company has equity and notes receivable interests in two power generating facilities. APUC has determined that both entities are considered VIEs mainly based on total equity at risk not being sufficient to permit the legal entity to finance its activities without additional subordinated financial support. The key decisions that affect the generating facilities’ economic performance relate to siting, permitting, technology, construction, operations and maintenance and financing. As APUC has both the power to direct the activities of the entities that most significantly impact its economic performance and the right to receive benefits or the obligation to absorb losses of the entities that could potentially be significant to the entity, the Company is considered the primary beneficiary.
Total net book value of generating assets and long-term debt of these facilities amounts to $60,230 (2018 - $59,288) and $21,754 (2018 - $22,263), respectively. The financial performance of these facilities reflected on the consolidated statements of operations includes non-regulated energy sales of $17,108 (2018 - $17,232), operating expenses and amortization of $4,930 (2018 - $4,634) and interest expense of $2,340 (2018 - $2,557).

(n) | Long-term investments and notes receivable

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

Notes to the Consolidated Financial Statements – APUC 2019 Annual Report | 72

Algonquin Power & Utilities Corp.
Notes to the Consolidated Financial Statements
December 31, 2019 and 2018
(in thousands of U.S. dollars, except as noted and per share amounts)

1. | Significant accounting policies (continued)

(n) | Long-term investments and notes receivable (continued)

Notes receivable are financial assets with fixed or determined payments that are not quoted in an active market. Notes receivable are initially recorded at cost, which is generally face value. Subsequent to acquisition, the notes receivable are recorded at amortized cost using the effective interest method. The Company holds these notes receivable as long-term investments and does not intend to sell these instruments prior to maturity. Interest from long-term investments is recorded as earned and when collectability of both the interest and principal are reasonably assured.
If a loss in value of a long-term investment is considered other than temporary, an allowance for impairment on the investment is recorded for the amount of that loss. An allowance for impairment loss on notes receivable is recorded if it is expected that the Company will not collect all principal and interest contractually due. The impairment is measured based on the present value of expected future cash flows discounted at the note’s effective interest rate.

(o) | Pension and other post-employment plans

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

(p) | Asset retirement obligations

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

(q) | Leases

The Company adopted ASU 2016-02, Leases (Topic 842) (“ASC 842”) during 2019 using a modified retrospective approach.
The Company leases buildings, vehicles, rail cars, and office equipment for use in its day-to-day operations. The Company has options to extend the lease term of many of its lease agreements, with renewal periods ranging from one to five years. As at the consolidated balance sheet date, the Company is not reasonably certain that these renewal options will be exercised.

Notes to the Consolidated Financial Statements – APUC 2019 Annual Report | 73

Algonquin Power & Utilities Corp.
Notes to the Consolidated Financial Statements
December 31, 2019 and 2018
(in thousands of U.S. dollars, except as noted and per share amounts)

1. | Significant accounting policies (continued)

(q) | Leases (continued)

The Renewable Energy Group enters into land easement agreements for the operation of its generation facilities. In assessing whether these contracts contain leases, the Company considers whether it has exclusive use of the land. In the majority of situations, the landowner or grantor of the easement still has full access to the land and can use the land in any capacity, as long as it does not interfere with the Company’s operations. Therefore, these land easement agreements do not contain leases. For land easement agreements that provide exclusive access to and use of the land, these agreements meet the definition of a lease and are within the scope of ASC 842.
The Regulated Services Group enters into easement agreements for the operation of its utilities. For all easements that existed or were expired as of January 1, 2019, the practical expedient was taken to not change the legacy accounting for these easement contracts. For new easement contracts entered into subsequent to January 1, 2019, the Company considers whether they contain a lease.
The implementation of ASC 842 did not have an impact on the Company’s existing finance leases. The weighted-average discount rate as of December 31, 2019 for the Company’s finance lease assets and liabilities is 6.45% and the weighted-average remaining lease term of the Company’s finance leases is 5.55 years.
New right-of-use assets and lease liabilities of $8,295 were recognized for the Company’s operating leases as at January 1, 2019. As a result of the acquisition of Enbridge Gas New Brunswick Limited Partnership (“New Brunswick Gas”) on October 1, 2019 (note 3(a)), the Company acquired new right-of-use assets and assumed lease liabilities of $1,316. The weighted-average discount rate as of December 31, 2019 for the Company’s operating lease assets and liabilities is 3.95% and the weighted-average remaining lease term is 13.49 years.
The right-of-use assets are included in property, plant and equipment while lease liabilities are included in other liabilities on the consolidated balance sheets.
The Company’s operating leases payments for the next five years and thereafter are as follows:

Year 1 |  | Year 2 |  | Year 3 |  | Year 4 |  | Year 5 |  | Thereafter |  | Total
$ | 2,115 |  |  | $ | 1,138 |  |  | $ | 688 |  |  | $ | 659 |  |  | $ | 642 |  |  | $ | 5,195 |  |  | $ | 10,437 |

The lease payments for the Company’s finance leases are expected to be approximately $539 annually for the next five years, and $318 thereafter.

(r) | Share-based compensation

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

(s) | Non-controlling interests

Non-controlling interests represent the portion of equity ownership in subsidiaries that is not attributable to the equity holders of APUC. Non-controlling interests are initially recorded at fair value and subsequently adjusted for the proportionate share of earnings and other comprehensive income (“OCI”) attributable to the non-controlling interests and any dividends or distributions paid to the non-controlling interests.
If a transaction results in the acquisition of all, or part, of a non-controlling interest in a consolidated subsidiary, the acquisition of the non-controlling interest is accounted for as an equity transaction. No gain or loss is recognized in net earnings or comprehensive income as a result of changes in the non-controlling interest, unless a change results in the loss of control by the Company.

Notes to the Consolidated Financial Statements – APUC 2019 Annual Report | 74

Algonquin Power & Utilities Corp.
Notes to the Consolidated Financial Statements
December 31, 2019 and 2018
(in thousands of U.S. dollars, except as noted and per share amounts)

1. | Significant accounting policies (continued)

(s) | Non-controlling interests (continued)

Certain of the Company’s U.S. based wind and solar businesses are organized as limited liability corporations (“LLCs”) and partnerships and have non-controlling membership equity investors (“tax equity partnership units”, or “Tax Equity Investors”), which are entitled to allocations of earnings, tax attributes and cash flows in accordance with contractual agreements. These LLCs and partnership agreements have liquidation rights and priorities that are different from the underlying percentage ownership interests. In those situations, simply applying the percentage ownership interest to U.S. GAAP net income in order to determine earnings or losses would not accurately represent the income allocation and cash flow distributions that will ultimately be received by the investors. As such, the share of earnings attributable to the non-controlling interest holders in these entities is calculated using the Hypothetical Liquidation at Book Value (“HLBV”) method of accounting (note 17).
The HLBV method uses a balance sheet approach. A calculation is prepared at each balance sheet date to determine the amount that Tax Equity Investors would receive if an equity investment entity were to liquidate all of its assets and distribute that cash to the investors based on the contractually defined liquidation priorities. The difference between the calculated liquidation distribution amounts at the beginning and the end of the reporting period is the Tax Equity Investors’ share of the earnings or losses from the investment for that period. Due to certain mandatory liquidation provisions of the LLC and partnership agreements, this could result in a net loss to APUC’s consolidated results in periods in which the Tax Equity Investors report net income. The calculation varies in its complexity depending on the capital structure and the tax considerations of the investments.
Equity instruments subject to redemption upon the occurrence of uncertain events not solely within APUC’s control are classified as temporary equity and presented as redeemable non-controlling interests on the consolidated balance sheets. The Company records temporary equity at issuance based on cash received less any transaction costs. As needed, the Company reevaluates the classification of its redeemable instruments, as well as the probability of redemption. If the redemption amount is probable or currently redeemable, the Company records the instruments at their redemption value. Increases or decreases in the carrying amount of a redeemable instrument are recorded within deficit. When the redemption feature lapses or other events cause the classification of an equity instrument as temporary equity to be no longer required, the existing carrying amount of the equity instrument is reclassified to permanent equity at the date of the event that caused the reclassification.

(t) | Recognition of revenue

The Company accounts for revenue in accordance with ASC Topic 606, Revenue from Contracts with Customers, which was adopted on January 1, 2018 using the modified retrospective method, applied to contracts that were not completed at the date of initial application. The adoption of the new standard resulted in an adjustment of $2,488 or $1,860 net of taxes to increase opening retained earnings for previously deferred revenue related to the Empire fiber business.
Revenue is recognized when control of the promised goods or services is transferred to the Company’s customers in an amount that reflects the consideration the Company expects to be entitled to in exchange for those goods or services.
Refer to note 21, “Segmented information” for details of revenue disaggregation by business units.

Notes to the Consolidated Financial Statements – APUC 2019 Annual Report | 75

Algonquin Power & Utilities Corp.
Notes to the Consolidated Financial Statements
December 31, 2019 and 2018
(in thousands of U.S. dollars, except as noted and per share amounts)

1. | Significant accounting policies (continued)

(t) | Recognition of revenue (continued)

Regulated Services Group revenue
Regulated Services Group revenues consist primarily of the distribution of electricity, natural gas, and water.
Revenue related to utility electricity and natural gas sales and distribution is recognized over time as the energy is delivered. At the end of each month, the electricity and natural gas delivered to the customers from the date of their last meter read to the end of the month is estimated and the corresponding unbilled revenue is recorded. These estimates of unbilled revenue and sales are based on the ratio of billable days versus unbilled days, amount of electricity or natural gas procured during that month, historical customer class usage patterns, weather, line loss, unaccounted-for gas and current tariffs. Unbilled receivables are typically billed within the next month. Some customers elect to pay their bill on an equal monthly plan. As a result, in some months cash is received in advance of the delivery of electricity. Deferred revenue is recorded for that amount. The amount of revenue recognized in the period from the balance of deferred revenue is not significant.
Water reclamation and distribution revenue is recognized over time when water is processed or delivered to customers. At the end of each month, the water delivered and wastewater collected from the customers from the date of their last meter read to the end of the month are estimated and the corresponding unbilled revenue is recorded. These estimates of unbilled revenue are based on the ratio of billable days versus unbilled days, amount of water procured and collected during that month, historical customer class usage patterns and current tariffs. Unbilled receivables are typically billed within the next month.
On occasion, a utility is permitted to implement new rates that have not been formally approved by the regulatory commission, which are subject to refund. The Company recognizes revenue based on the interim rate and, if needed, establishes a reserve for amounts that could be refunded based on experience for the jurisdiction in which the rates were implemented.
Revenue for certain of the Company’s regulated utilities is subject to alternative revenue programs approved by their respective regulators. Under these programs, the Company charges approved annual delivery revenue on a systematic basis over the fiscal year. As a result, the difference between delivery revenue calculated based on metered consumption and approved delivery revenue is disclosed as alternative revenue in note 21, “Segmented information” and is recorded as a regulatory asset or liability to reflect future recovery or refund, respectively, from customers (note 7). The amount subsequently billed to customers is recorded as a recovery of the regulatory asset.
Renewable Energy Group revenue
Renewable Energy Group’s revenue consists primarily of the sale of electricity, capacity, and renewable energy credits.
Revenue related to the sale of electricity is recognized over time as the electricity is delivered. The electricity represents a single performance obligation that represents a promise to transfer to the customer a series of distinct goods that are substantially the same and that have the same pattern of transfer to the customer.
Revenues related to the sale of capacity are recognized over time as the capacity is provided. The nature of the promise to provide capacity is that of a stand-ready obligation. The capacity is generally expressed in monthly volumes and prices. The capacity represents a single performance obligation that represents a promise to transfer to the customer a series of distinct services that are substantially the same and that have the same pattern of transfer to the customer.
Qualifying renewable energy projects receive renewable energy credits (“RECs”) and solar renewable energy credits (“SRECs”) for the generation and delivery of renewable energy to the power grid. The energy credit certificates represent proof that 1 MW of electricity was generated from an eligible energy source. The RECs and SRECs can be traded and the owner of the RECs or SRECs can claim to have purchased renewable energy. RECs and SRECs are primarily sold under fixed contracts, and revenue for these contracts is recognized at a point in time, upon generation of the associated electricity. Any RECs or SRECs generated above contracted amounts are held in inventory, with the offset recorded as a decrease in operating expenses.

Notes to the Consolidated Financial Statements – APUC 2019 Annual Report | 76

Algonquin Power & Utilities Corp.
Notes to the Consolidated Financial Statements
December 31, 2019 and 2018
(in thousands of U.S. dollars, except as noted and per share amounts)

1. | Significant accounting policies (continued)

(t) | Recognition of revenue (continued)

Renewable Energy Group revenue (continued)
The Company has elected to apply the invoicing practical expedient to the electricity and capacity in the Renewable Energy Group contracts. The Company does not disclose the value of unsatisfied performance obligations for these contracts as revenue is recognized at the amount to which the Company has the right to invoice for services performed.
Revenue is recorded net of sales taxes.

(u) | Foreign currency translation

APUC’s reporting currency is the U.S. dollar. Within these consolidated financial statements, the Company denotes any amounts denominated in Canadian dollars with “C$” immediately prior to the stated amount.
The Company’s Canadian operations are determined to have the Canadian dollar as their functional currency since the preponderance of operating, financing and investing transactions are denominated in Canadian dollars. The financial statements of these operations are translated into U.S. dollars using the current rate method, whereby assets and liabilities are translated at the rate prevailing at the balance sheet date, and revenue and expenses are translated using average rates for the period. Unrealized gains or losses arising as a result of the translation of the financial statements of these entities are reported as a component of OCI and are accumulated in a component of equity on the consolidated balance sheets, and are not recorded in income unless there is a complete or substantially complete sale or liquidation of the investment.
Subsequent to year-end, effective January 1, 2020, the functional currency of APUC, the non-consolidated parent entity, changed from the Canadian dollar to the U.S. dollar based on a balance of facts taking into consideration its operating, financing and investing activities. As a result of the entity’s change of functional currency, changes were made to certain hedging relationships to mitigate the remaining Canadian dollar risk.

(v) | Income taxes

Income taxes are accounted for using the asset and liability method. Deferred tax assets and liabilities are recognized for the future tax consequences attributable to differences between the financial statement carrying amounts of assets and liabilities and their respective tax bases. Deferred tax assets and liabilities are measured using enacted tax rates expected to apply to taxable income in the years in which those temporary differences are expected to be recovered or settled. A valuation allowance is recorded against deferred tax assets to the extent that it is considered more likely than not that the deferred tax asset will not be realized. The effect on deferred tax assets and liabilities of a change in tax rates is recognized in earnings in the period that includes the date of enactment (note 18). Investment tax credits for the rate regulated operations are deferred and amortized as a reduction to income tax expense over the estimated useful lives of the properties. Investment tax credits along with other income tax credits in the non-regulated operations are treated as a reduction to income tax expense in the year the credit arises.
The organizational structure of APUC and its subsidiaries is complex and the related tax interpretations, regulations and legislation in the tax jurisdictions in which they operate are continually changing. As a result, there can be tax matters that have uncertain tax positions. The Company recognizes the effect of income tax positions only if those positions are more likely than not of being sustained. Recognized income tax positions are measured at the largest amount that is greater than 50% likely of being realized. Changes in recognition or measurement are reflected in the period in which the change in judgment occurs.
(w)Financial instruments and derivatives
Accounts receivable and notes receivable are measured at amortized cost. Long-term debt and Series C preferred shares are measured at amortized cost using the effective interest method, adjusted for the amortization or accretion of premiums or discounts.

Notes to the Consolidated Financial Statements – APUC 2019 Annual Report | 77

Algonquin Power & Utilities Corp.
Notes to the Consolidated Financial Statements
December 31, 2019 and 2018
(in thousands of U.S. dollars, except as noted and per share amounts)

1. | Significant accounting policies (continued)

(w)Financial instruments and derivatives (continued)
Transaction costs that are directly attributable to the acquisition of financial assets are accounted for as part of the asset’s carrying value at inception. Transaction costs related to a recognized debt liability are presented in the consolidated balance sheets as a direct deduction from the carrying amount of that debt liability, consistent with debt discounts and premiums. Costs of arranging the Company’s revolving credit facilities and intercompany loans are recorded in other assets. Deferred financing costs, premiums and discounts on long-term debt are amortized using the effective interest method while deferred financing costs relating to the revolving credit facilities and intercompany loans are amortized on a straight-line basis over the term of the respective instrument.
The Company uses derivative financial instruments as one method to manage exposures to fluctuations in exchange rates, interest rates and commodity prices. APUC recognizes all derivative instruments as either assets or liabilities on the consolidated balance sheets at their respective fair values. The fair value recognized on derivative instruments executed with the same counterparty under a master netting arrangement are presented on a gross basis on the consolidated balance sheets. The amounts that could net settle are not significant. The Company applies hedge accounting to some of its financial instruments used to manage its foreign currency risk, interest rate risk and price risk exposures associated with sales of generated electricity.
For derivatives designated in a cash flow hedge relationship, the change in fair value is recognized in OCI. The amount recognized in AOCI is reclassified to earnings in the same period as the hedged cash flows affect earnings under the same line item in the consolidated statements of operations as the hedged item. If the hedging instrument no longer meets the criteria for hedge accounting, expires or is sold, terminated, exercised, or the designation is revoked, then hedge accounting is discontinued prospectively. The amount remaining in AOCI is transferred to the consolidated statements of operations in the same period that the hedged item affects earnings. If the forecasted transaction is no longer expected to occur, then the balance in AOCI is recognized immediately in earnings.
Foreign currency gain or loss on derivative or financial instruments designated as a hedge of the foreign currency exposure of a net investment in foreign operations that are effective as a hedge are reported in the same manner as the translation adjustment (in OCI) related to the net investment.
The Company’s electric distribution and thermal generation facilities enter into power and gas purchase contracts for load serving and generation requirements. These contracts meet the exemption for normal purchase and normal sales and, as such, are not required to be recorded at fair value as derivatives and are accounted for on an accrual basis. Counterparties are evaluated on an ongoing basis for non-performance risk to ensure it does not impact the conclusion with respect to this exemption.
(x)Fair value measurements
The Company utilizes valuation techniques that maximize the use of observable inputs and minimize the use of unobservable inputs to the extent possible. The Company determines fair value based on assumptions that market participants would use in pricing an asset or liability in the principal or most advantageous market. When considering market participant assumptions in fair value measurements, the following fair value hierarchy distinguishes between observable and unobservable inputs, which are categorized in one of the following levels:

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

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

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

(y) | Commitments and contingencies

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

Notes to the Consolidated Financial Statements – APUC 2019 Annual Report | 78

Algonquin Power & Utilities Corp.
Notes to the Consolidated Financial Statements
December 31, 2019 and 2018
(in thousands of U.S. dollars, except as noted and per share amounts)

1. | Significant accounting policies (continued)

(z) | Use of estimates

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

(a) | Recently adopted accounting pronouncements

The FASB issued accounting standards update (“ASU”) 2018-15, Intangibles — Goodwill and Other Internal-Use Software (Subtopic 350-40): Customer’s Accounting for Implementation Costs Incurred in a Cloud Computing Arrangement that is a Service Contract to provide additional guidance to address diversity in practice. This update aligns the requirements for capitalizing implementation costs incurred in a hosting arrangement that is a service contract with the requirements for capitalizing implementation costs incurred to develop or obtain internal-use software. The Company adopted this update prospectively as at the beginning of the third quarter. There were no significant impacts to the consolidated financial statements as a result of the adoption of this update.
The FASB issued ASU 2018-16, Derivatives and Hedging (Topic 815): Inclusion of the Secured Overnight Financing Rate (“SOFR”) Overnight Index Swap (“OIS”) Rate as a Benchmark Interest Rate for Hedge Accounting Purposes to identify a suitable alternative to the U.S. dollar LIBOR that is more firmly based on actual transactions in a robust market. This update permits the use of the OIS rate based on SOFR as a U.S. benchmark interest rate for hedge accounting purposes. This update was adopted concurrently with ASU 2017-12. The Company will follow the pronouncements prospectively for qualifying new or redesignated hedging relationships.
The FASB issued ASU 2018-07, Compensation — Stock Compensation (Topic 718): Improvements to Non-employee Share-Based Payment Accounting to expand the scope of Topic 718 to include share-based payment transactions for acquiring goods and services from non-employees. This update changes the measurement basis and date of non-employee share-based payment awards and also makes amendments to how to measure non-employee awards with performance conditions. The adoption of this update in 2019 had no impact on the Company’s consolidated financial statements.
The FASB issued ASU 2017-12, Derivatives and Hedging (Topic 815): Targeted Improvements to Accounting for Hedging Activities, to improve the financial reporting of hedging relationships to better portray the economic results of an entity’s risk management activities in its financial statements. The update also makes certain targeted improvements to simplify the application of the hedge accounting guidance. The FASB also issued ASU 2019-04 that contains further codification improvements to ASU 2017-12. The adoption of these updates in 2019 resulted in a reclassification of $186 from retained earnings to accumulated other comprehensive income for previous hedge ineffectiveness recognized in earnings for outstanding hedging contracts. The Company has also made certain amendments and simplifications to hedge effectiveness testing procedures and documentation to be followed prospectively where applicable in accordance with the pronouncements in the update.

Notes to the Consolidated Financial Statements – APUC 2019 Annual Report | 79

Algonquin Power & Utilities Corp.
Notes to the Consolidated Financial Statements
December 31, 2019 and 2018
(in thousands of U.S. dollars, except as noted and per share amounts)

2. Recently issued accounting pronouncements (continued)

(a) | Recently adopted accounting pronouncements (continued)

The FASB issued ASU 2017-11, Earnings Per Share (Topic 260); Distinguishing Liabilities from Equity (Topic 480); Derivatives and Hedging (Topic 815): (Part I) Accounting for Certain Financial Instruments with Down Round Features, (Part II) Replacement of the Indefinite Deferral for Mandatorily Redeemable Financial Instruments of Certain Nonpublic Entities and Certain Mandatorily Redeemable Noncontrolling Interests with a Scope Exception to address narrow issues with applying U.S. GAAP for certain financial instruments with characteristics of liabilities and equity. The adoption of this update in 2019 had no impact on the consolidated financial statements.
The FASB issued ASU 2016-02, Leases (Topic 842) to increase transparency and comparability among organizations utilizing leases. This ASU requires lessees to recognize the assets and liabilities arising from all leases on the balance sheet, but the effect of leases in the statement of operations and the statement of cash flows is largely unchanged. The FASB also issued subsequent amendments to ASC 842 that provide further practical expedients as well as codification clarifications and improvements. The adoption of this new lease standard in 2019 using a modified retrospective approach resulted in an adjustment of $8,295 to right-of-use assets and operating lease liabilities included in other long-term liabilities on the consolidated balance sheets, with no restatement of the comparative period.
The Company implemented new processes and procedures for the identification, analysis, and measurement of new lease contracts. A new software solution was implemented to assist with contract management, information tracking, and measurement as it relates to the new standard. The Company elected the following practical expedients as part of its adoption:

1. | “Package of three” practical expedient that permits the Company not to reassess the scope, classification and initial direct costs of its expired and existing leases;

2. | Land easements practical expedient that permits the Company not to reassess the accounting for land easements previously not accounted for under Leases ASC 840; and

3. | Hindsight practical expedient that allows the Company to use hindsight in determining the lease term for existing contracts.

In addition, the Company made an accounting policy election to not recognize a lease liability or right-of-use asset on its consolidated balance sheets for short-term leases (lease term less than 12 months).

(b) | Recently issued accounting guidance not yet adopted

The FASB issued ASU 2020-01, Investments - Equity Securities (Topic 321), Investments — Equity Method and Joint Ventures (Topic 323), and Derivatives and Hedging (Topic 815): Clarifying the Interactions between Topic 321, Topic 323, and Topic 815 to reduce diversity in practice and increase comparability of accounting for certain transactions. The amendments clarify when to consider observable price changes for the measurement of certain equity securities without a readily determinable fair value. They also clarify the scope of forward contracts and purchased options on these certain securities. The amendments in this update are effective for fiscal years beginning after December 15, 2020, and interim periods within those years. Early adoption is permitted, including early adoption in any interim period. The Company currently does not have any transactions that would be within the scope of this update but will continue to assess the impact of this update in the future.
The FASB issued ASU 2019-12, Income Taxes (Topic 740): Simplifying the Accounting for Income Taxes as part of its initiative to reduce complexity in the accounting standards. The amendments remove certain exceptions to the general principles in Topic 740 and improve consistent application for other areas of Topic 740 by clarifying and amending existing guidance. The amendments in this update are effective for fiscal years beginning after December 15, 2020, and interim periods within those years. Early adoption is permitted, but all amendments must be early adopted simultaneously. The Company is currently assessing the impact of this update.

Notes to the Consolidated Financial Statements – APUC 2019 Annual Report | 80

Algonquin Power & Utilities Corp.
Notes to the Consolidated Financial Statements
December 31, 2019 and 2018
(in thousands of U.S. dollars, except as noted and per share amounts)

2. Recently issued accounting pronouncements (continued)

(b) | Recently issued accounting guidance not yet adopted (continued)

The FASB issued ASU 2018-18, Collaborative Arrangements (Topic 808): Clarifying the Interaction between Topic 808 and Topic 606 to reduce diversity in practice on how entities account for transactions on the basis of different views of the economics of a collaborative arrangement. The update clarifies that the arrangement should be accounted for under ASC 606 when a participant is a customer in the context of a unit of account, adds unit of account guidance in ASC 808 that is consistent with ASC 606, and precludes the recognition of revenue from a collaborative arrangement with ASC 606 revenue if the participant is not directly related to sales to third parties. The amendments in this update are effective for fiscal years beginning after December 15, 2019, and interim periods within those years. The Company does not expect a significant impact on its consolidated financial statements as a result of the adoption of this update.
The FASB issued ASU 2018-17, Consolidation (Topic 810): Targeted Improvements to Related Party Guidance for Variable Interest Entities to improve general purpose financial reporting. The update clarifies that indirect interests held through related parties in common control arrangements should be considered on a proportional basis for determining whether fees paid to decision makers and service providers are variable interests. The amendments in the update are effective for fiscal years beginning after December 15, 2019 and interim periods within those fiscal years. The amendments are required to be applied retrospectively with a cumulative-effect adjustment to retained earnings. The Company does not expect a significant impact on its consolidated financial statements as a result of the adoption of this update.
The FASB issued ASU 2017-04, Business Combinations (Topic 350): Intangibles — Goodwill and Other (Topic 350): Simplifying the Test for Goodwill Impairment. The update is intended to simplify how an entity is required to test goodwill for impairment by eliminating Step 2 from the goodwill impairment test. Step 2 measures a goodwill impairment loss by comparing the implied fair value of a reporting unit’s goodwill with the carrying amount of that goodwill. The standard is effective for fiscal years and interim periods beginning after December 15, 2019. The Company does not expect a significant impact on its consolidated financial statements as a result of the adoption of this update.
The FASB issued ASU 2016-13, Financial Instruments — Credit Losses (Topic 326): Measurement of Credit Losses on Financial Instruments to provide financial statement users with more decision-useful information about the expected credit losses on financial instruments and other commitments to extend credit held by a reporting entity at each reporting date. To achieve this objective, the amendments in this update replace the incurred loss impairment methodology in current U.S. GAAP with a methodology that reflects expected credit losses. The standard is effective for fiscal years and interim periods beginning after December 15, 2019. The FASB issued codification improvements to ASC Topic 326 in ASU 2018-19 to provide guidance on scoping of operating lease assets and further specific clarifications and corrections in ASU 2019-04 and ASU 2019-11. The FASB issued further updates to Topic 326 in ASU 2019-05 and ASU 2020-02 to provide transition relief that allows companies to irrevocably elect the fair value option for certain instruments held at amortized cost, and to provide certain updates to the SEC paragraphs of the topic. The Company is finalizing its analysis on the impact of adoption of this standard on its consolidated financial statements. The Company does not expect a significant impact on its consolidated financial statements as a result of the adoption of this update.

Notes to the Consolidated Financial Statements – APUC 2019 Annual Report | 81

Algonquin Power & Utilities Corp.
Notes to the Consolidated Financial Statements
December 31, 2019 and 2018
(in thousands of U.S. dollars, except as noted and per share amounts)

3. | Business acquisitions and development projects

(a) | Acquisition of Enbridge Gas New Brunswick Limited Partnership & St. Lawrence Gas Company Inc.

The Company completed the acquisition of New Brunswick Gas on October 1, 2019, and St. Lawrence Gas Company, Inc. (“St. Lawrence Gas”) on November 1, 2019. New Brunswick Gas is a regulated utility that provides natural gas. The purchase price is approximately $256,011 (C$339,036). St. Lawrence Gas is a regulated utility that provides natural gas in northern New York State. The total purchase price for the transaction is $61,820, and subject to certain closing adjustments.
The costs related to the acquisitions have been expensed through the consolidated statements of operations.
The following table summarizes the preliminary allocation of the assets acquired and liabilities assumed at the acquisition date:

| New Brunswick Gas | St. Lawrence Gas
Working capital | $ | 8,782 |  | $ | 3,403 |
Property, plant and equipment | 137,668 |  | 49,936 |
Goodwill | 56,054 |  | 20,259 |
Regulatory assets | 94,827 |  | 3,562 |
Deferred income tax assets, net | — |  | 1,614 |
Other assets | 125 |  | 6,418 |
Regulatory liabilities | (2,076 | ) | (10,412 | )
Pension and post-employment benefits | — |  | (12,376 | )
Deferred income tax liability, net | (38,053 | ) | — |
Other liabilities | (1,316 | ) | (584 | )
Total net assets acquired | $ | 256,011 |  | $ | 61,820 |
Cash and cash equivalent | 7,248 |  | 1,225 |
Total net assets acquired, net of cash and cash equivalent | $ | 248,763 |  | $ | 60,595 |

The determination of the fair value of assets acquired and liabilities assumed is based upon management’s preliminary estimates and certain assumptions. Due to the timing of the acquisitions, the Company has not finalized the fair value measurements. The Company will continue to review information and perform further analysis prior to finalizing the fair value of the consideration paid and the fair value of assets acquired and liabilities assumed.
Goodwill represents the excess of the purchase price over the aggregate fair value of net assets acquired. The contributing factors to the amount recorded as goodwill include future growth, potential synergies, and cost savings in the delivery of certain shared administrative and other services.
Property, plant and equipment, exclusive of computer software, are amortized in accordance with regulatory requirements over the estimated useful life of the assets using the straight-line method. The weighted average useful life of New Brunswick Gas and St. Lawrence Gas’ assets is 47 years and 49 years, respectively.

Notes to the Consolidated Financial Statements – APUC 2019 Annual Report | 82

Algonquin Power & Utilities Corp.
Notes to the Consolidated Financial Statements
December 31, 2019 and 2018
(in thousands of U.S. dollars, except as noted and per share amounts)

3. | Business acquisitions and development projects (continued)

(b) | Acquisition of Turquoise Solar Facility

Liberty Utilities (Turquoise Holdings) LLC (“Turquoise Holdings”) is owned by Liberty Utilities (Calpeco Electric) LLC (“Calpeco Electric System”). The 10 MWac solar generating facility is located in Washoe County, Nevada (“Turquoise Solar Facility”). On May 24, 2019, a tax equity agreement was executed. The Class A partnership units are owned by a third-party tax equity investor who funded $1,403 on the execution date and $2,000 on December 31, 2019. The final instalments are expected to be made in 2020. With its interest, the tax equity investor will receive the majority of the tax attributes associated with the Turquoise Solar Facility. Because the Class A tax equity investor has the right to withdraw from Turquoise Holdings and require the Company to redeem its remaining interests for cash, the Company accounts for this interest as “Redeemable non-controlling interest” outside of permanent equity on the consolidated balance sheets (note 17). Redemption is not considered probable as of December 31, 2019.
On December 31, 2019, as the Turquoise Solar Facility was placed in service, Turquoise Holdings obtained control of the property, plant and equipment for a total purchase price of $20,830.

(c) | Agreement to acquire Mid-West Wind Development Project

The Empire District Electric Company (“Empire Electric System”), a wholly owned subsidiary of the Company, entered into purchase agreements to acquire, once completed, three wind farms generating up to 600 MW of wind energy located in Barton, Dade, Lawrence, and Jasper Counties in Missouri (“Missouri Wind Projects”) and in Neosho County, Kansas (“Kansas Wind Project”). The agreements contain development milestones and termination provisions that primarily apply prior to the commencement of construction. Total costs are estimated at $1,100,000 and the acquisitions are anticipated to close following completion of the respective projects. These assets, net of third-party tax equity investment, are expected to be included in the rate base of the Empire Electric System.
In November 2019, Liberty Utilities Co, a wholly owned subsidiary of the Company, acquired an interest in the entities that own the two Missouri Wind Projects and, in partnership with a third-party developer, will continue development and construction of such projects until they are acquired by the Empire Electric System following completion. As part of the investment in the joint ventures, Liberty Utilities Co. entered into guarantee agreements for obligations under letters of credit, engineering and procurement contracts, and turbine supply agreements for the two projects. The Company accounts for its interest in these two projects using the equity method (note 8(d)).
In November 2019, a tax equity agreement was executed for the Kansas Wind Project. The Class A partnership units will be owned by two third-party tax equity investors who have committed to fund on a future date. With their interests, the tax equity investors will receive the majority of the tax attributes associated with the Kansas Wind Project. Initial tax equity funding is expected to be received in Q1 2021.
(d)Agreement to acquire New York American Water
On November 20, 2019, the Company entered into an agreement to acquire American Water’s regulated operations in the State of New York (“New York American Water”). New York American Water is a regulated water and wastewater utility serving customers across seven counties in southeastern New York. The total purchase price for the transaction is approximately $608,000, subject to certain closing adjustments. The transaction is expected to close sometime in 2021 and remains subject to regulatory approval and other typical closing conditions.

(e) | Agreement to acquire Bermuda Electric Light Company

On June 3, 2019, the Company entered into an agreement to acquire the Ascendant Group Limited (“Ascendant”), parent company of Bermuda Electric Light Company. Bermuda Electric Light Company is the sole electric utility providing regulated electrical generation, transmission and distribution services to Bermuda’s residents and businesses. The total purchase price for the transaction is approximately $365,000. Closing of the transaction remains subject to shareholder and regulatory approvals and is expected in 2020.

Notes to the Consolidated Financial Statements – APUC 2019 Annual Report | 83

Algonquin Power & Utilities Corp.
Notes to the Consolidated Financial Statements
December 31, 2019 and 2018
(in thousands of U.S. dollars, except as noted and per share amounts)

3. | Business acquisitions and development projects (continued)

(f) | Approval to acquire the Perris Water Distribution System

On August 10, 2017, the Company agreed to acquire two water distribution systems serving customers from the City of Perris, California. The anticipated purchase price of $11,500 is expected to be established as rate base during the regulatory approval process. The City of Perris residents voted to approve the sale on November 7, 2017. The Regulated Services Group filed an application requesting approval for the acquisition of the assets of the water utilities with the California Public Utility Commission on May 8, 2018. Final approval is expected in 2020.

(g) | Great Bay Solar Facilities

The Great Bay Solar I and II Facilities are 75 and 40 MWac solar powered generating facilities in Somerset County, Maryland. Commercial operations as defined by the power purchase agreement was reached for all sites at the Great Bay Solar I Facility by March 29, 2018. As of December 31, 2019, one site at the Great Gay Solar II Facility has been fully synchronized with the power grid, while the remaining site is expected to be placed in service in early 2020.
The Great Bay Solar I Facility is controlled by a subsidiary of APUC (Great Bay Holdings, LLC). The Class A partnership units are owned by a third-party tax equity investor who funded $42,750 in 2017 with the remaining amount of $15,250 received in 2018. Through its partnership interest, the tax equity investor will receive the majority of the tax attributes associated with the project. The Company accounts for this interest as “Non-controlling interest” on the consolidated balance sheets.
The Great Bay Solar II Facility is controlled by Great Bay Holdings, LLC. Liberty Utilities (America) Holdco, a subsidiary of APUC, is the tax equity investor for the facility and contributed initial funding of $11,281 in December 2019. The facility generated an investment tax credit of $8,526 during the year, which was recorded by the Company as a reduction to income tax expense in the consolidated statement of operations.

4. | Accounts receivable

Accounts receivable as of December 31, 2019 include unbilled revenue of $80,295 (2018 - $79,742) from the Company’s regulated utilities. Accounts receivable as of December 31, 2019 are presented net of allowance for doubtful accounts of $4,939 (2018 - $5,281).

5. | Property, plant and equipment

Property, plant and equipment consist of the following:

2019 |  |  |  |  |
| Cost |  | Accumulated depreciation |  | Net book value
Generation | $ | 2,816,611 |  |  | $ | 540,118 |  |  | $ | 2,276,493 |
Distribution and transmission | 4,988,297 |  |  | 598,449 |  |  | 4,389,848 |
Land | 74,517 |  |  | — |  |  | 74,517 |
Equipment and other | 94,583 |  |  | 47,541 |  |  | 47,042 |
Construction in progress |  |  |  |  |
Generation | 140,235 |  |  | — |  |  | 140,235 |
Distribution and transmission | 303,529 |  |  | — |  |  | 303,529 |
| $ | 8,417,772 |  |  | $ | 1,186,108 |  |  | $ | 7,231,664 |

Notes to the Consolidated Financial Statements – APUC 2019 Annual Report | 84

Algonquin Power & Utilities Corp.
Notes to the Consolidated Financial Statements
December 31, 2019 and 2018
(in thousands of U.S. dollars, except as noted and per share amounts)

5. | Property, plant and equipment (continued)

2018 |  |  |  |  |
| Cost |  | Accumulated depreciation |  | Net book value
Generation | $ | 2,470,279 |  |  | $ | 450,230 |  |  | $ | 2,020,049 |
Distribution and transmission | 4,455,935 |  |  | 521,236 |  |  | 3,934,699 |
Land | 73,773 |  |  | — |  |  | 73,773 |
Equipment and other | 88,757 |  |  | 41,295 |  |  | 47,462 |
Construction in progress |  |  |  |  |
Generation | 104,996 |  |  | — |  |  | 104,996 |
Distribution and transmission | 212,579 |  |  | — |  |  | 212,579 |
| $ | 7,406,319 |  |  | $ | 1,012,761 |  |  | $ | 6,393,558 |

Generation assets include cost of $109,653 (2018 - $104,107) and accumulated depreciation of $39,638 (2018 - $34,916) related to facilities under financing lease or owned by consolidated VIEs. Depreciation expense of facilities under finance leases was $1,615 (2018 - $1,987).
Distribution and transmission assets include the following:

• | Cost of $1,450,946 (2018 - $1,383,960) and accumulated depreciation of $97,080 (2018 - $69,960) related to regulated generation and transmission assets.

• | Cost of $514,709 (2018 - $503,664) and accumulated depreciation of $31,349 (2018 - $21,697) related to commonly owned facilities (note 1(k)). Total expenditures incurred on these facilities for the year ended December 31, 2019 were $69,210 (2018 - $75,427).

• | Cost of $3,076 (2018 - $3,076) and accumulated depreciation of $1,003 (2018 - $669) related to assets under finance lease.

• | Expansion costs of $1,000 on which the Company does not currently earn a return.

For the year ended December 31, 2019, contributions received in aid of construction of $7,137 (2018 - $6,057) have been credited to the cost of the assets.
Interest and AFUDC capitalized to the cost of the assets in 2019 and 2018 are as follows:

|  | 2019 |  | 2018
Interest capitalized on non-regulated property |  | $ | 4,538 |  |  | $ | 2,268 |
AFUDC capitalized on regulated property: |  |  |  |
Allowance for borrowed funds |  | 2,745 |  |  | 1,684 |
Allowance for equity funds |  | 4,896 |  |  | 2,728 |
Total |  | $ | 12,179 |  |  | $ | 6,680 |

6. | Intangible assets and goodwill

Intangible assets consist of the following:

2019 | Cost |  | Accumulated amortization |  | Net book value
Power sales contracts | $ | 56,206 |  |  | $ | 38,931 |  |  | $ | 17,275 |
Customer relationships | 26,797 |  |  | 10,104 |  |  | 16,693 |
Interconnection agreements | 14,827 |  |  | 1,179 |  |  | 13,648 |
| $ | 97,830 |  |  | $ | 50,214 |  |  | $ | 47,616 |

Notes to the Consolidated Financial Statements – APUC 2019 Annual Report | 85

Algonquin Power & Utilities Corp.
Notes to the Consolidated Financial Statements
December 31, 2019 and 2018
(in thousands of U.S. dollars, except as noted and per share amounts)

6. | Intangible assets and goodwill (continued)

2018 | Cost |  | Accumulated amortization |  | Net book value
Power sales contracts | $ | 60,775 |  |  | $ | 36,063 |  |  | $ | 24,712 |
Customer relationships | 26,795 |  |  | 9,476 |  |  | 17,319 |
Interconnection agreements | 13,847 |  | — |  | 884 |  |  | 12,963 |
| $ | 101,417 |  |  | $ | 46,423 |  |  | $ | 54,994 |

Estimated amortization expense for intangible assets for the next year is $2,018, $2,190 in year two, $2,350 in year three, $1,910 in year four and $1,780 in year five.
All goodwill pertains to the Regulated Services Group.

Balance, December 31, 2018 and 2017 |  | $ | 954,282 |
Business acquisitions (note 3(a)) |  | 76,313 |
Foreign exchange |  | 1,101 |
Balance, December 31, 2019 |  | $ | 1,031,696 |

7. | Regulatory matters

The operating companies within the Regulated Services Group are subject to regulation by the public utility commissions of the states and provinces in which they operate. The respective public utility commissions have jurisdiction with respect to rate, service, accounting policies, issuance of securities, acquisitions and other matters. These utilities operate under cost-of-service regulation as administered by these authorities. The Company’s regulated utility operating companies are accounted for under the principles of ASC 980. Under ASC 980, regulatory assets and liabilities that would not be recorded under U.S. GAAP for non-regulated entities are recorded to the extent that they represent probable future revenue or expenses associated with certain charges or credits that will be recovered from or refunded to customers through the rate setting process.
During 2019, the Company completed the acquisition of New Brunswick Gas and St. Lawrence Gas, operating public utilities engaged in the distribution of natural gas in the Province of New Brunswick and the state of New York, respectively. New Brunswick Gas is subject to regulation by the New Brunswick Energy and Utilities Board. St. Lawrence Gas is subject to regulation by the New York Public Service Commission. In general, the commissions set rates at a level that allows the utilities to collect total revenues or revenue requirements equal to the cost of providing service, plus an appropriate return on invested capital.
At any given time, the Company can have several regulatory proceedings underway. The financial effects of these proceedings are reflected in the consolidated financial statements based on regulatory approval obtained to the extent that there is a financial impact during the applicable reporting period. The following regulatory proceedings were recently completed:

Utility | State | Regulatory proceeding type | Annual revenue increase | Effective date
Peach State Gas System | Georgia | Georgia Rate Adjustment mechanism | $2,367 | February 1, 2019
New England Natural Gas System | Massachusetts | Gas System Enhancement Plan | $2,413 | May 1, 2019
Empire Electric System | Kansas | General Rate Review | $2,449 | August 1, 2019
Empire Electric System | Oklahoma | General Rate Review | $1,400 | October 1, 2019
CalPeco Electric System | California | Catastrophic Events Memorandum Account | $3,525 | January 1, 2020

Notes to the Consolidated Financial Statements – APUC 2019 Annual Report | 86

Algonquin Power & Utilities Corp.
Notes to the Consolidated Financial Statements
December 31, 2019 and 2018
(in thousands of U.S. dollars, except as noted and per share amounts)

7. | Regulatory matters (continued)

Regulatory assets and liabilities consist of the following:

| 2019 |  | 2018
Regulatory assets |  |  |
Environmental remediation (a) | $ | 82,300 |  |  | $ | 82,295 |
Pension and post-employment benefits (b) | 143,292 |  |  | 135,580 |
Income taxes (c) | 71,506 |  |  | 34,822 |
Debt premium (d) | 42,150 |  |  | 48,847 |
Fuel and commodity cost adjustments (e) | 23,433 |  |  | 26,310 |
Rate adjustment mechanism (f) | 69,121 |  |  | 37,202 |
Clean Energy and other customer programs (g) | 26,369 |  |  | 24,095 |
Deferred capitalized costs (h) | 38,833 |  |  | 13,986 |
Asset retirement obligation (i) | 23,841 |  |  | 21,048 |
Long-term maintenance contract (j) | 13,264 |  |  | 8,283 |
Rate review costs (k) | 6,695 |  |  | 6,164 |
Other | 19,083 |  |  | 21,463 |
Total regulatory assets | $ | 559,887 |  |  | $ | 460,095 |
Less: current regulatory assets | (50,213 | ) |  | (59,037 | )
Non-current regulatory assets | $ | 509,674 |  |  | $ | 401,058 |
Regulatory liabilities |  |  |
Income taxes (c) | $ | 321,960 |  |  | $ | 323,384 |
Cost of removal (l) | 196,423 |  |  | 193,564 |
Rate base offset (m) | 8,719 |  |  | 10,900 |
Fuel and commodity costs adjustments (e) | 16,645 |  |  | 21,352 |
Rate adjustment mechanism (f) | 10,446 |  |  | 4,210 |
Deferred capitalized costs - fuel related (h) | 7,097 |  |  | 7,258 |
Pension and post-employment benefits (b) | 22,256 |  |  | 11,791 |
Other | 14,516 |  |  | 15,754 |
Total regulatory liabilities | $ | 598,062 |  |  | $ | 588,213 |
Less: current regulatory liabilities | (41,683 | ) |  | (39,005 | )
Non-current regulatory liabilities | $ | 556,379 |  |  | $ | 549,208 |

Notes to the Consolidated Financial Statements – APUC 2019 Annual Report | 87

Algonquin Power & Utilities Corp.
Notes to the Consolidated Financial Statements
December 31, 2019 and 2018
(in thousands of U.S. dollars, except as noted and per share amounts)

7. | Regulatory matters (continued)

(a) | Environmental remediation

Actual expenditures incurred for the clean-up of certain former gas manufacturing facilities (note 12(b)) are recovered through rates over a period of 7 years and are subject to an annual cap.

(b) | Pension and post-employment benefits

As part of certain business acquisitions, the regulators authorized a regulatory asset or liability being set up for the amounts of pension and post-employment benefits that have not yet been recognized in net periodic cost and were presented as AOCI prior to the acquisition. The balance is recovered through rates over the future service years of the employees at the time the regulatory asset was set up (an average of 10 years) or consistent with the treatment of OCI under ASC 712, Compensation Non-retirement Post-employment Benefits and ASC 715, Compensation Retirement Benefits before the transfer to regulatory asset occurred. The annual movements in AOCI for Empire Electric and Gas systems’ and St. Lawrence Gas system’s pension and OPEB plans (note 10(a)) are also reclassified to regulatory accounts since it is probable the unfunded amount of these plans will be afforded rate recovery. Finally, the regulators have also approved tracking accounts for a number of the utilities. The amounts recorded in these accounts occur when actual expenses differ from those adopted and recovery or refunds are expected to occur in future periods.

(c) | Income taxes

The income taxes regulatory assets and liabilities represent income taxes recoverable through future revenues required to fund flow-through deferred income tax liabilities and amounts owed to customers for deferred taxes collected at a higher rate than the current statutory rates.
On June 1, 2018, the State of Missouri enacted legislation that, effective for tax years beginning on or after January 1, 2020, reduces the corporate income tax rate from 6.25% to 4%, among other legislative changes. A reduction of regulatory asset and an increase to regulatory liability were recorded for excess deferred taxes probable of being refunded to customers of $15,586.

(d) | Debt premium

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

(e) | Fuel and commodity cost adjustments

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

(f) | Rate adjustment mechanism

Revenue for Calpeco Electric System, Park Water System, Peach State Gas System, New England Gas System, Midstates Natural Gas system, and EnergyNorth Natural Gas System is subject to a revenue decoupling mechanism approved by their respective regulator, which requires charging approved annual delivery revenue on a systematic basis over the fiscal year. As a result, the difference between delivery revenue calculated based on metered consumption and approved delivery revenue is recorded as a regulatory asset or liability to reflect future recovery or refund, respectively, from customers. In addition, retroactive rate adjustments for services rendered but to be collected over a period not exceeding 24 months are accrued upon approval of the Final Order. The difference between New Brunswick Gas’ regulated revenues and its regulated cost of service in past years is also recorded as a regulatory asset and is recovered on a straight-line basis over the next 25 years.

(g) | Clean Energy and other customer programs

The regulatory asset for Clean Energy and customer programs includes initiatives related to solar rebate applications processed and resulting rebate-related costs. The amount also includes other energy efficiency programs.

Notes to the Consolidated Financial Statements – APUC 2019 Annual Report | 88

Algonquin Power & Utilities Corp.
Notes to the Consolidated Financial Statements
December 31, 2019 and 2018
(in thousands of U.S. dollars, except as noted and per share amounts)

7. | Regulatory matters (continued)

(h) | Deferred capitalized costs

Deferred capitalized costs reflect deferred construction costs and fuel-related costs of specific generating facilities of the Empire Electric System. These amounts are being recovered over the life of the plants. The amount also includes capitalized operating and maintenance costs of New Brunswick Gas, and these amounts are being recovered at a rate of 2.43% annually over the next 29 years.

(i) | Asset retirement obligation

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

(j) | Long-term maintenance contract

To the extent actual costs of long-term maintenance incurred for one of Empire Electric System’s power plants differ from the costs recoverable through current rates, that difference is deferred and recorded as a regulatory asset or liability on the consolidated balance sheets.

(k) | Rate review costs

The costs to file, prosecute and defend rate review applications are referred to as rate review costs. These costs are capitalized and amortized over the period of rate recovery granted by the regulator.

(l) | Cost of removal

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

(m) | Rate base offset

The regulators imposed a rate base offset that will reduce the revenue requirement at future rate proceedings. The rate base offset declines on a straight-line basis over a period of 10-16 years.
As recovery of regulatory assets is subject to regulatory approval, if there were any changes in regulatory positions that indicate recovery is not probable, the related cost would be charged to earnings in the period of such determination. The Company generally earns carrying charges on the regulatory balances related to commodity cost adjustment, retroactive rate adjustments and rate review costs.

8. | Long-term investments

Long-term investments consist of the following:

| 2019 |  | 2018
Long-term investments carried at fair value |  |  |
Atlantica (a) | $ | 1,178,581 |  |  | $ | 814,530 |
AYES Canada (b) | 88,494 |  |  | — |
San Antonio Water System (c) | 27,072 |  |  | — |
| $ | 1,294,147 |  |  | $ | 814,530 |
Other long-term investments |  |  |
Equity-method investees (d) | $ | 83,770 |  |  | $ | 29,588 |
Development loans receivable from equity-method investees (e) | 36,204 |  |  | 101,417 |
Other | 1,994 |  |  | 4,773 |
Total other long-term investments | $ | 121,968 |  |  | $ | 135,778 |
Less: current portion | — |  |  | (1,407 | )
| $ | 121,968 |  |  | $ | 134,371 |

Notes to the Consolidated Financial Statements – APUC 2019 Annual Report | 89

Algonquin Power & Utilities Corp.
Notes to the Consolidated Financial Statements
December 31, 2019 and 2018
(in thousands of U.S. dollars, except as noted and per share amounts)

8. | Long-term investments (continued)

Income (loss) from long-term investments from the years ended December 31, 2019 and 2018 is as follows:

| Year ended December 31
| 2019 |  | 2018
Fair value gain (loss) on investments carried at fair value |  |  |
Atlantica | $ | 290,740 |  |  | $ | (137,957 | )
AYES Canada | (6,649 | ) |  | — |
San Antonio Water System | (6,007 | ) |  | — |
| $ | 278,084 |  |  | $ | (137,957 | )
Dividend and interest income from investments carried at fair value |  |  |
Atlantica | $ | 69,307 |  |  | $ | 39,263 |
AYES Canada | 25,572 |  |  | — |
San Antonio Water System | 6,007 |  |  | — |
| $ | 100,886 |  |  | $ | 39,263 |
Other long-term investments |  |  |  |  |
Equity method loss | (9,108 | ) |  | (3,082 | )
Interest and other income | 29,230 |  |  | 16,958 |
| $ | 399,092 |  |  | $ | (84,818 | )

(a) | Investment in Atlantica

AAGES (AY Holdings) B.V. (“AY Holdings”), an entity controlled and consolidated by APUC, has a share ownership in Atlantica Yield plc (“Atlantica”) of approximately 44.2% (December 31, 2018 - 41.5%). APUC has the flexibility, subject to certain conditions, to increase its ownership of Atlantica up to 48.5%. In 2019, the Company purchased 1,384,402 treasury shares of Atlantica for cash consideration of $30,000. In addition, 2,000,000 shares were received pursuant to a prepayment of $53,750. Subsequent to year-end, the prepayment purchase agreement settled with no material cash difference. During 2018, APUC purchased from Abengoa S.A. (“Abengoa”) a 41.5% equity interest in Atlantica through two transactions for a total purchase price of $952,567, with a holdback of $40,000 of which $29,100 was settled in 2019 with the balance payable at a later date, subject to certain conditions. The Company has elected the fair value option under ASC 825, Financial Instruments to account for its investment in Atlantica, with changes in fair value reflected in the consolidated statements of operations.
On November 28, 2018, Abengoa-Algonquin Global Energy Solutions B.V. (“AAGES B.V.”), an equity investee of the Company, obtained a three-year secured credit facility in the amount of $306,500 and subscribed to a $305,000 preference share ownership interest in AY Holdings. The subscription proceeds were distributed by AY Holdings to the Company and used by the Company to repay the $305,000 of temporary financing used for the 2018 investment in Atlantica. The AAGES B.V. secured credit facility is collateralized through a pledge of the Atlantica shares held by AY Holdings. A collateral shortfall would occur if the net obligation as defined in the agreement would equal or exceed 50% of the market value of the Atlantica shares in which case the lenders would have the right to sell Atlantica stock to eliminate the collateral shortfall. The AAGES B.V. secured credit facility is repayable on demand if Atlantica ceases to be a public company. APUC reflects the preference share ownership issued by AY Holdings as redeemable non-controlling interest held by related party (note 17).

Notes to the Consolidated Financial Statements – APUC 2019 Annual Report | 90

Algonquin Power & Utilities Corp.
Notes to the Consolidated Financial Statements
December 31, 2019 and 2018
(in thousands of U.S. dollars, except as noted and per share amounts)

8. | Long-term investments (continued)

(b) | Investment in AYES Canada

On May 24, 2019, APUC and Atlantica formed Atlantica Yield Energy Solutions Canada Inc. (“AYES Canada”), a vehicle to channel co-investment opportunities in which Atlantica holds the majority of voting rights. The first investment was Windlectric Inc. (“Windlectric”). APUC invested $91,918 (C$123,603) and Atlantica invested $4,834 (C$6,500) in AYES Canada, which in turn invested those funds in Amherst Island Partnership (“AIP”), the holding company of Windlectric.
APUC continues to control and consolidate AIP and Windlectric. The investment of $96,752 (C$130,103) by AYES Canada in AIP is presented as a non-controlling interest held by a related party (notes 16 and 17). The AIP partnership agreement has liquidation rights and priorities to each equity holder that are different from the underlying percentage ownership interests. As such, the share of earnings attributable to the non-controlling interest holder is calculated using the HLBV method of accounting. The Company incurred non-controlling interest calculated using the HLBV method of accounting of $nil and recorded distributions of $26,465 (C$34,373) during the year.
AYES Canada is considered to be a VIE based on the disproportionate voting and economic interests of the shareholders. Atlantica is considered to be the primary beneficiary of AYES Canada. Accordingly, APUC’s investment in AYES Canada is considered an equity method investment. Under the AYES Canada shareholders agreement, starting in May 2020, APUC has the option to exchange approximately 3,500,000 shares of AYES Canada into ordinary shares of Atlantica on a one-for-one basis, subject to certain conditions. Consistent with the treatment of the Atlantica shares, the Company has elected the fair value option under ASC 825, Financial Instruments to account for its investment in AYES Canada, with changes in fair value reflected in the consolidated statements of operations. A level 3 discounted cash flow approach combined with the binomial tree approach were used to estimate the fair value of the investment. For the year, APUC recorded dividend income of $25,572 and a fair value loss of $6,649 on its investment in AYES Canada.
As at December 31, 2019, the Company’s maximum exposure to loss is $88,494, which represents the fair value of the investment.

(c) | San Antonio Water System

On May 1, 2019, APUC invested $17,000 by way of a secured loan into AWUSA VR Holding LLC (“AWUSA”), a wholly owned subsidiary of Abengoa. An additional amount of $5,000 plus interest is payable at a later date, subject to certain conditions. The loan is secured by AWUSA’s investment in the Vista Ridge water pipeline project. The Vista Ridge water pipeline project is a 140 mile water pipeline from Burleson County, Texas, to San Antonio, Texas. Since APUC has the power to direct the activities of AWUSA and benefits from the economics of this entity, the Company consolidates AWUSA. AWUSA’s 20% interest in Vista Ridge is accounted for using the equity method.
On December 30, 2019, the Company and a third-party developer each contributed C$1,500 to the capital of a new joint venture, created for the purpose of developing infrastructure investment opportunities. The Company sold its investment in AWUSA to the joint venture in exchange for a loan receivable of $30,293. A note payable to AWUSA of $13,293 was recognized by the Company upon deconsolidation of AWUSA. The Company holds an option exercisable at any time to acquire the remaining interest at a pre-agreed price. The sale was accounted for in accordance with ASC 860, Transfers and Servicing and no gain or loss was recognized.
The joint venture is considered to be a VIE due to insufficient equity at risk to finance its operations with additional subordinated financial support. Neither APUC nor the third-party developer is considered to be the primary beneficiary since each party holds 50% voting and economic interests. Accordingly, APUC’s investment in the joint venture is considered an equity method investment. The Company has elected the fair value option under ASC 825, Financial Instruments to account for its investment, with changes in fair value reflected in the consolidated statements of operations. A level 3 discounted cash flow approach was used to estimate the fair value of the investment. For the year, APUC recorded interest income of $6,007 and a fair value loss of $6,007 on its investment in the joint venture.
As of December 31, 2019, the Company’s maximum exposure to loss is $27,072, which represents the fair value of the investment.

Notes to the Consolidated Financial Statements – APUC 2019 Annual Report | 91

Algonquin Power & Utilities Corp.
Notes to the Consolidated Financial Statements
December 31, 2019 and 2018
(in thousands of U.S. dollars, except as noted and per share amounts)

8. | Long-term investments (continued)

(d)Equity-method investees
The Company has non-controlling interests in various partnerships and joint ventures with a total carrying value of $83,770 (2018 - $29,588) including investments in VIEs of $59,091 (2018 - $9,581).
The Company owns a 75% interest ownership in Red Lily I, an operating 26.4 MW wind facility. APUC exercises significant influence over operating and financial policies of the Red Lily I Wind Facility. Due to certain participating rights being held by the minority investor, the decisions that which most significantly impact the economic performance of the Red Lily I Wind Facility require unanimous consent. As such, the Company accounts for the partnership using the equity method.
The Company also has 50% interests in a number of wind and solar power electric development projects and infrastructure development projects. The Company holds an option to acquire the remaining 50% interest in most development projects at a pre-agreed price. Some of the development projects include AAGES, the international development platform established with Abengoa in 2018; Sugar Creek, a 202 MW wind power development project in Logan County, Illinois; Maverick, a 490 MW wind project located in Concho County, Texas; Altavista, a 80 MW solar power project located in Campbell County, Virginia, and two approximately 150 MW wind projects in southwestern Missouri.
On April 16, 2019, the Company acquired the remaining 50% interest in Windlectric which owns a 75 MW wind generating facility (“Amherst Island Wind Facility”) in the Province of Ontario for $6,362. Prior to this acquisition, APUC’s 50% interest in Windlectric was recorded as an equity investment. As a result of obtaining control of the facility, the transaction was treated as an asset acquisition. APUC recorded the fair value on that date for property, plant and equipment acquired of $311,175, deferred tax asset of $3,015, working capital of $14,280 and liabilities of $1,600 for asset retirement obligation assumed; and, derecognized the existing development loan between the two parties of $316,786 (note 8(e)).
Summarized combined information for APUC’s investments in significant partnerships and joint ventures is as follows:

| 2019 |  | 2018
Total assets | $ | 833,791 |  |  | $ | 360,372 |
Total liabilities | 697,751 |  |  | 335,331 |
Net assets | 136,040 |  |  | 25,041 |
APUC’s ownership interest in the entities | 63,624 |  |  | 18,042 |
Difference between investment carrying amount and underlying equity in net assets(a) | 18,487 |  |  | 11,048 |
APUC’s investment carrying amount for the entities | $ | 82,111 |  |  | $ | 29,090 |

(a) The difference between the investment carrying amount and the underlying equity in net assets relates primarily to interest capitalized while the projects are under construction, the fair value of guarantees provided by the Company in regards to the investments and transaction costs.
Except for AAGES BV, the development projects are considered VIEs due to the level of equity at risk and the disproportionate voting and economic interests of the shareholders. The Company has committed loan and credit support facilities with some of its equity investees. During construction, the Company is obligated to provide cash advances (note 8(e)) and credit support in amounts necessary for the continued development and construction of the equity investees’ projects. As of December 31, 2019, the Company had issued letters of credit and guarantees of obligations under a security of performance for a development opportunity; wind turbine or solar panel supply agreements; engineering, procurement, and construction agreements; purchase and sale agreements; interconnection agreements; energy purchase agreements; renewable energy credit agreements; equity capital contribution agreements; landowner agreements; and bridge loan agreements. The fair value of the support provided recorded as at December 31, 2019 amounts to $9,493 (2018 - $1,682). The Company is not considered the primary beneficiary of these entities as the partners have joint control and all decisions must be unanimous. Therefore, the Company accounts for its interest in these VIEs using the equity method.

Notes to the Consolidated Financial Statements – APUC 2019 Annual Report | 92

Algonquin Power & Utilities Corp.
Notes to the Consolidated Financial Statements
December 31, 2019 and 2018
(in thousands of U.S. dollars, except as noted and per share amounts)

8. | Long-term investments (continued)

(d)Equity-method investees (continued)
Summarized combined information for APUC’s VIEs is as follows:

| 2019 |  | 2018
APUC’s maximum exposure in regards to VIEs |  |  |
Carrying amount | $ | 59,091 |  |  | $ | 9,581 |
Development loans receivable (e) | 35,000 |  |  | 101,417 |
Commitments on behalf of VIEs | 1,364,871 |  |  | 120,669 |
| $ | 1,458,962 |  |  | $ | 231,667 |

The majority of the amounts committed on behalf of VIEs in the above relate to wind turbine or solar panel supply agreements as well as engineering, procurement, and construction agreements.

(e) | Development loans receivable from equity investees

The Company has committed loan and credit support facilities with some of its equity investees. During construction, the Company is obligated to provide cash advances and credit support (in the form of letters of credit, escrowed cash, guarantees or indemnities) in amounts necessary for the continued development and construction of the equity investees’ projects. The loans bear interest at a weighted average annual rate of 7.66% (2018 - 9.90%) on outstanding principal and generally mature on the commercial operation date.

9. | Long-term debt

Long-term debt consists of the following:

Borrowing type |  | Weighted average coupon |  | Maturity |  | Par value |  | 2019 |  | 2018
Senior unsecured revolving credit facilities (a) |  | — |  |  | 2023-2024 |  | N/A |  |  | $ | 141,577 |  |  | $ | 97,000 |
Senior unsecured bank credit facilities (b) |  | — |  |  | 2020 |  | N/A |  |  | 75,000 |  |  | 321,807 |
Commercial paper (c) |  | — |  |  | 2020 |  | N/A |  |  | 218,000 |  |  | 6,000 |
U.S. dollar borrowings |  |  |  |  |  |  |  |  |  |
Senior unsecured notes |  | 4.09 | % |  | 2020-2047 |  | $ | 1,225,000 |  |  | 1,219,579 |  |  | 1,218,680 |
Senior unsecured utility notes |  | 6.00 | % |  | 2020-2035 |  | $ | 217,000 |  |  | 233,686 |  |  | 240,161 |
Senior secured utility bonds |  | 4.75 | % |  | 2020-2044 |  | $ | 662,500 |  |  | 672,337 |  |  | 676,697 |
Canadian dollar borrowings |  |  |  |  |  |  |  |  |  |
Senior unsecured notes (d) |  | 4.48 | % |  | 2021-2029 |  | C$ | 950,669 |  |  | 728,679 |  |  | 474,764 |
Senior secured project notes |  | 10.22 | % |  | 2020-2027 |  | C$ | 28,503 |  |  | 21,961 |  |  | 22,915 |
|  |  |  |  |  |  |  | $ | 3,310,819 |  |  | $ | 3,058,024 |
Subordinated U.S. dollar borrowings |  |  |  |  |  |  |  |  |  |
Subordinated unsecured notes (e) |  | 6.50 | % |  | 2078-2079 |  | $ | 637,500 |  |  | 621,049 |  |  | 278,771 |
|  |  |  |  |  |  |  | $ | 3,931,868 |  |  | $ | 3,336,795 |
Less: current portion |  |  |  |  |  |  |  | (225,013 | ) |  | (13,048 | )
|  |  |  |  |  |  |  | $ | 3,706,855 |  |  | $ | 3,323,747 |

Short-term obligations of $377,015 that are expected to be refinanced using the long-term credit facilities are presented as long-term debt.

Notes to the Consolidated Financial Statements – APUC 2019 Annual Report | 93

Algonquin Power & Utilities Corp.
Notes to the Consolidated Financial Statements
December 31, 2019 and 2018
(in thousands of U.S. dollars, except as noted and per share amounts)

9. | Long-term debt (continued)

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

(a) | Senior unsecured revolving credit facilities

On October 24, 2019, the Company entered into a new $75,000 uncommitted bilateral letter of credit facility. The facility matures on October 24, 2020.
On July 12, 2019, the Company entered into a new $500,000 senior unsecured revolving bank credit facility that matures July 12, 2024. The interest rate is equal to the bankers’ acceptance or LIBOR plus a credit spread. The existing C$165,000 credit facility was canceled.
On February 23, 2018, the Regulated Services Group increased commitments under its credit facility to $500,000 and extended the maturity to February 23, 2023. Concurrent with this amendment, the Regulated Services Group closed Empire’s credit facility. The Regulated Services Group’s credit facility will now be used as a backstop for Empire’s commercial paper program and as a source of liquidity for Empire.
During 2018, the Renewable Energy Group extended the maturity of its senior unsecured revolving bank credit facility from October 6, 2022 to October 6, 2023. On February 16, 2018, the Renewable Energy Group increased availability under its revolving letter of credit facility to $200,000 and extended the maturity to January 31, 2021. Subsequent to year-end, on February 24, 2020, the Renewable Energy Group increased its uncommitted Renewable Energy LC Facility to $350,000 and extended the maturity to June 30, 2021.

(b) | Senior unsecured bank credit facilities

On June 27, 2019, the Regulated Services Group extended the maturity of its $135,000 term loan to July 6, 2020. During the year, the Company repaid $60,000 of the facility.
On March 7, 2018, the Company drew $600,000 under a new term credit facility. The balance was repaid in 2018 except for a balance of $186,807, which was repaid on May 23, 2019.

(c) | Commercial paper

On July 1, 2019, the Regulated Services Group established a new $500,000 commercial paper program. The amounts drawn at any time under this program may have maturities up to 270 days from the date of issuance and are expected to be replaced with new commercial paper upon maturity. This program is backstopped by the Regulated Services Group’s bank credit facility.

(d) | Canadian dollar senior unsecured notes

Subsequent to year-end, on February 14, 2020, the Regulated Services Group issued C$200,000 senior unsecured debentures bearing interest at 3.315% with a maturity date of February 14, 2050. The debentures are redeemable at the option of the Company at any time at a predetermined price.
On January 29, 2019, the Renewable Energy Group issued C$300,000 senior unsecured notes bearing interest at 4.60% with a maturity date of January 29, 2029. The notes were sold at a price of C$99.952 per C$100.00 principal amount. Concurrent with the financing, the Renewable Energy Group unwound and settled the related forward-starting interest rate swap on a notional bond of C$135,000 (note 24(b)(ii)).
On July 25, 2018, the Company repaid, upon its maturity, a C$135,000 unsecured note.
(e)Subordinated unsecured notes
On May 23, 2019, the Company issued $350,000 unsecured, 6.20% fixed-to-floating subordinated notes (“subordinated notes”) maturing on July 1, 2079. Concurrent with the offering, the Company entered into a cross-currency swap to convert the U.S. dollar denominated coupon and principal payments from the offering into Canadian dollars.

Notes to the Consolidated Financial Statements – APUC 2019 Annual Report | 94

Algonquin Power & Utilities Corp.
Notes to the Consolidated Financial Statements
December 31, 2019 and 2018
(in thousands of U.S. dollars, except as noted and per share amounts)

9. | Long-term debt (continued)

(e)Subordinated unsecured notes (continued)
Beginning on July 1, 2024, and on every quarter thereafter that the subordinated notes are outstanding (the “interest reset date”) until July 1, 2029, the subordinated notes will be reset at an interest rate of the three-month LIBOR plus 4.01%, payable in arrears. In September 2019, the Company entered into forward-starting interest rate swaps to convert its variable interest rate to fixed for the period of July 1, 2024 to July 1, 2029 (note 24(b)(ii)). Beginning on July 1, 2029, and on every interest reset date until July 1, 2049, the subordinated notes will be reset at an interest rate of the three-month LIBOR plus 4.26%, payable in arrears. Beginning on July 1, 2049, and on every interest reset date until July 1, 2079, the subordinated notes will be reset at an interest rate of the three-month LIBOR plus 5.01%, payable in arrears.
The Company may elect, at its sole option, to defer the interest payable on the subordinated notes on one or more occasions for up to five consecutive years. Deferred interest will accrue, compounding on each subsequent interest payment date, until paid. Additionally, on or after July 1, 2024, the Company may, at its option, redeem the subordinated notes, at a redemption price equal to 100% of the principal amount, together with accrued and unpaid interest.
On October 17, 2018, the Company completed the issuance of $287,500 unsecured, 6.875% fixed-to-floating subordinated notes (“subordinated notes”) maturing on October 17, 2078. Beginning on October 17, 2023, and on every quarter thereafter that the subordinated notes are outstanding (the “interest reset date”) until October 17, 2028, the subordinated notes will be reset at an interest rate of the three-month LIBOR plus 3.677%, payable in arrears. Beginning on October 17, 2028, and on every interest reset date until October 17, 2043, the subordinated notes will be reset at an interest rate of the three-month LIBOR plus 3.927%, payable in arrears. Beginning on October 17, 2043, and on every interest reset date until October 17, 2078, the subordinated notes will be reset at an interest rate of the three-month LIBOR plus 4.677%, payable in arrears.
The Company may elect, at its sole option, to defer the interest payable on the subordinated notes on one or more occasions for up to five consecutive years. Deferred interest will accrue, compounding on each subsequent interest payment date, until paid. Additionally, on or after October 17, 2023, the Company may, at its option, redeem the subordinated notes, at a redemption price equal to 100% of the principal amount, together with accrued and unpaid interest.
As of December 31, 2019, the Company had accrued $44,229 in interest expense (2018 - $33,822). Interest expense on the long-term debt, net of capitalized interest, in 2019 was $175,664 (2018 - $146,310).
Principal payments due in the next five years and thereafter are as follows:

2020 |  | 2021 |  | 2022 |  | 2023 |  | 2024 |  | Thereafter |  | Total
$ | 602,028 |  |  | $ | 117,513 |  |  | $ | 351,227 |  |  | $ | 97,478 |  |  | $ | 215,743 |  |  | $ | 2,547,916 |  |  | $ | 3,931,905 |

10. | Pension and other post-employment benefits

The Company provides defined contribution pension plans to substantially all of its employees. The Company’s contributions for 2019 were $8,798 (2018 - $8,446).
In conjunction with the utility acquisitions, the Company assumes defined benefit pension, supplemental executive retirement plans and OPEB plans for qualifying employees in the related acquired businesses. The legacy plans of the electricity and gas utilities are non-contributory defined pension plans covering substantially all employees of the acquired businesses. Benefits are based on each employee’s years of service and compensation. The Company also provides a defined benefit cash balance pension plan covering substantially all its new employees and current employees at its water utilities, under which employees are credited with a percentage of base pay plus a prescribed interest rate credit. The OPEB plans provide health care and life insurance coverage to eligible retired employees. Eligibility is based on age and length of service requirements and, in most cases, retirees must cover a portion of the cost of their coverage.

Notes to the Consolidated Financial Statements – APUC 2019 Annual Report | 95

Algonquin Power & Utilities Corp.
Notes to the Consolidated Financial Statements
December 31, 2019 and 2018
(in thousands of U.S. dollars, except as noted and per share amounts)

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

(a) | Net pension and OPEB obligation

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

| Pension benefits |  | OPEB
| 2019 |  | 2018 |  | 2019 |  | 2018
Change in projected benefit obligation |  |  |  |  |  |  |
Projected benefit obligation, beginning of year | $ | 484,707 |  |  | $ | 531,694 |  |  | $ | 168,325 |  |  | $ | 176,975 |
Projected benefit obligation assumed from business combination | 20,196 |  |  | — |  |  | 11,646 |  |  | — |
Modifications to plans | (7,705 | ) |  | — |  |  | — |  |  | — |
Service cost | 12,351 |  |  | 15,481 |  |  | 4,587 |  |  | 5,791 |
Interest cost | 20,222 |  |  | 19,077 |  |  | 7,575 |  |  | 6,727 |
Actuarial (gain) loss | 65,443 |  |  | (29,986 | ) |  | 33,605 |  |  | (14,800 | )
Contributions from retirees | — |  |  | — |  |  | 1,913 |  |  | 1,878 |
Gain on curtailment | — |  |  | (1,875 | ) |  | — |  |  | — |
Medicare Part D | — |  |  | — |  |  | 414 |  |  | 42 |
Benefits paid | (30,244 | ) |  | (49,684 | ) |  | (8,848 | ) |  | (8,288 | )
Projected benefit obligation, end of year | $ | 564,970 |  |  | $ | 484,707 |  |  | $ | 219,217 |  |  | $ | 168,325 |
Change in plan assets |  |  |  |  |  |  |
Fair value of plan assets, beginning of year | 339,099 |  |  | 403,945 |  |  | 115,542 |  |  | 130,487 |
Plan assets acquired in business combination | 8,004 |  |  | — |  |  | 15,688 |  |  | — |
Actual return on plan assets | 68,025 |  |  | (36,987 | ) |  | 25,464 |  |  | (10,603 | )
Employer contributions | 22,190 |  |  | 21,825 |  |  | 8,628 |  |  | 2,026 |
Medicare Part D subsidy receipts | — |  |  | — |  |  | 414 |  |  | 42 |
Benefits paid | (30,244 | ) |  | (49,684 | ) |  | (6,863 | ) |  | (6,410 | )
Fair value of plan assets, end of year | $ | 407,074 |  |  | $ | 339,099 |  |  | $ | 158,873 |  |  | $ | 115,542 |
Unfunded status | $ | (157,896 | ) |  | $ | (145,608 | ) |  | $ | (60,344 | ) |  | $ | (52,783 | )
Amounts recognized in the consolidated balance sheets consist of: |  |  |  |  |  |  |
Non-current assets (note 11) | — |  |  | — |  |  | 8,437 |  |  | 3,161 |
Current liabilities | (1,415 | ) |  | (873 | ) |  | (1,168 | ) |  | (850 | )
Non-current liabilities | (156,481 | ) |  | (144,735 | ) |  | (67,613 | ) |  | (55,094 | )
Net amount recognized | $ | (157,896 | ) |  | $ | (145,608 | ) |  | $ | (60,344 | ) |  | $ | (52,783 | )

The accumulated benefit obligation for the pension plans was $526,517 and $439,458 as of December 31, 2019 and 2018, respectively.

Notes to the Consolidated Financial Statements – APUC 2019 Annual Report | 96

Algonquin Power & Utilities Corp.
Notes to the Consolidated Financial Statements
December 31, 2019 and 2018
(in thousands of U.S. dollars, except as noted and per share amounts)

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

(a) | Net pension and OPEB obligation (continued)

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

| Pension |  | OPEB
| 2019 |  | 2018 |  | 2019 |  | 2018
Accumulated benefit obligation | $ | 504,403 |  |  | $ | 439,458 |  |  | $ | 202,422 |  |  | $ | 163,375 |
Fair value of plan assets | $ | 407,074 |  |  | $ | 339,099 |  |  | $ | 133,711 |  |  | $ | 107,430 |

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

| Pension |  | OPEB
| 2019 |  | 2018 |  | 2019 |  | 2018
Projected benefit obligation | $ | 564,971 |  |  | $ | 476,791 |  |  | $ | 202,422 |  |  | $ | 163,375 |
Fair value of plan assets | $ | 407,074 |  |  | $ | 339,099 |  |  | $ | 133,711 |  |  | $ | 107,430 |

In 2019, the Company merged the Empire pension plan into the Company’s cash balance plan and defined benefit plans, and changed benefits for certain Empire participants. The total impact of these plan amendments resulted in a decrease to the projected benefit obligation of $7,798, which is recorded as a prior service credit in OCI.
In 2018, the Company permanently froze the accrual of benefits for participants in the Park Water System’s existing pension plan. Subsequent to the effective date, these employees began accruing benefits under the Company’s cash balance plan. The plan amendments resulted in a decrease to the projected benefit obligation of $1,875, which is recorded as a prior service credit in OCI.

(b) | Pension and post-employment actuarial changes

Change in AOCI (before tax) | Pension |  | OPEB
| Actuarial losses (gains) |  | Past service gains |  | Actuarial losses (gains) |  | Past service gains
Balance, January 1, 2018 | $ | 25,128 |  |  | $ | (4,995 | ) |  | $ | (3,182 | ) |  | $ | (470 | )
Additions to AOCI | 34,916 |  |  | (1,875 | ) |  | 3,254 |  |  | — |
Amortization in current period | (1,074 | ) |  | 649 |  |  | 272 |  |  | 262 |
Loss on plan settlements | $ | (2,547 | ) |  | $ | — |  |  | $ | — |  |  | $ | — |
Reclassification to regulatory accounts (note 7(b)) | (22,166 | ) |  | — |  |  | (14,232 | ) |  | — |
Balance, December 31, 2018 | $ | 34,257 |  |  | $ | (6,221 | ) |  | $ | (13,888 | ) |  | $ | (208 | )
AOCI from business acquisition | — |  |  | (285 | ) |  | — |  |  | — |
Additions to AOCI | 17,905 |  |  | (7,705 | ) |  | 14,871 |  |  | — |
Amortization in current period | (3,530 | ) |  | 784 |  |  | 409 |  |  | 208 |
Reclassification to regulatory accounts (note 7(b)) | (10,122 | ) |  | 7,247 |  |  | (10,538 | ) |  | — |
Balance, December 31, 2019 | $ | 38,510 |  |  | $ | (6,180 | ) |  | $ | (9,146 | ) |  | $ | — |

The movements in AOCI for Empire’s and St. Lawrence Gas’ pension and OPEB plans are reclassified to regulatory accounts since it is probable the unfunded amount of these plans will be afforded rate recovery (note 7(b)).

Notes to the Consolidated Financial Statements – APUC 2019 Annual Report | 97

Algonquin Power & Utilities Corp.
Notes to the Consolidated Financial Statements
December 31, 2019 and 2018
(in thousands of U.S. dollars, except as noted and per share amounts)

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

(c) | Assumptions

Weighted average assumptions used to determine net benefit obligation for 2019 and 2018 were as follows:

| Pension benefits |  | OPEB
| 2019 |  | 2018 |  | 2019 |  | 2018
Discount rate | 3.19 | % |  | 4.19 | % |  | 3.29 | % |  | 4.26 | %
Interest crediting rate (for cash balance plans) | 4.48 | % |  | 4.43 | % |  | N/A |  |  | N/A |
Rate of compensation increase | 4.00 | % |  | 4.00 | % |  | N/A |  |  | N/A |
Health care cost trend rate |  |  |  |  |  |  |
Before age 65 |  |  |  |  | 6.125 | % |  | 6.25 | %
Age 65 and after |  |  |  |  | 6.125 | % |  | 6.25 | %
Assumed ultimate medical inflation rate |  |  |  |  | 4.75 | % |  | 4.75 | %
Year in which ultimate rate is reached |  |  |  |  | 2031 |  |  | 2031 |

The mortality assumption for December 31, 2019 was updated to Pri-2012 mortality table and to the projected generationally scale MP-2019, adjusted to reflect the ultimate improvement rates in the 2019 Social Security Administration intermediate assumptions.
In selecting an assumed discount rate, the Company uses a modeling process that involves selecting a portfolio of high-quality corporate debt issuances (AA- or better) whose cash flows (via coupons or maturities) match the timing and amount of the Company’s expected future benefit payments. The Company considers the results of this modeling process, as well as overall rates of return on high-quality corporate bonds and changes in such rates over time, to determine its assumed discount rate.
The rate of return assumptions are based on projected long-term market returns for the various asset classes in which the plans are invested, weighted by the target asset allocations.
Weighted average assumptions used to determine net benefit cost for 2019 and 2018 were as follows:

| Pension benefits |  | OPEB
| 2019 |  | 2018 |  | 2019 |  | 2018
Discount rate | 4.19 | % |  | 3.57 | % |  | 4.25 | % |  | 3.60 | %
Expected return on assets | 6.87 | % |  | 7.13 | % |  | 6.51 | % |  | 6.52 | %
Rate of compensation increase | 4.00 | % |  | 3.00 | % |  | N/A |  |  | N/A |
Health care cost trend rate |  |  |  |  |  |  |
Before Age 65 |  |  |  |  | 6.25 | % |  | 6.25 | %
Age 65 and after |  |  |  |  | 6.25 | % |  | 6.25 | %
Assumed ultimate medical inflation rate |  |  |  |  | 4.75 | % |  | 4.75 | %
Year in which ultimate rate is reached |  |  |  |  | 2031 |  |  | 2024 |

Notes to the Consolidated Financial Statements – APUC 2019 Annual Report | 98

Algonquin Power & Utilities Corp.
Notes to the Consolidated Financial Statements
December 31, 2019 and 2018
(in thousands of U.S. dollars, except as noted and per share amounts)

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

(d) | Benefit costs

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

| Pension benefits |  | OPEB
| 2019 |  | 2018 |  | 2019 |  | 2018
Service cost | $ | 12,351 |  |  | $ | 15,481 |  |  | $ | 4,587 |  |  | $ | 5,791 |
Non-service costs |  |  |  |  |  |  |
Interest cost | 20,222 |  |  | 19,077 |  |  | 7,575 |  |  | 6,727 |
Expected return on plan assets | (20,485 | ) |  | (27,820 | ) |  | (6,725 | ) |  | (7,451 | )
Amortization of net actuarial loss (gain) | 3,530 |  |  | 1,074 |  |  | (409 | ) |  | (272 | )
Amortization of prior service credits | (784 | ) |  | (649 | ) |  | (208 | ) |  | (262 | )
Amortization of regulatory assets/liabilities | 12,082 |  |  | 10,584 |  |  | 2,534 |  |  | 3,982 |
| $ | 14,565 |  |  | $ | 2,266 |  |  | $ | 2,767 |  |  | $ | 2,724 |
Net benefit cost | $ | 26,916 |  |  | $ | 17,747 |  |  | $ | 7,354 |  |  | $ | 8,515 |

(e) | Plan assets

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

Asset class |  | Target (%) |  | Range (%)
Equity securities |  | 68 | % |  | 50% - 78%
Debt securities |  | 32 | % |  | 22% - 50%
|  | 100 | % |  |

The fair values of investments as of December 31, 2019, by asset category, are as follows:

Asset class |  | Level 1 |  | Percentage
Equity securities |  | $ | 414,985 |  |  | 73 | %
Debt securities |  | 141,229 |  |  | 25 | %
Other |  | 9,732 |  |  | 2 | %
|  | $ | 565,946 |  |  | 100 | %

As of December 31, 2019, the funds do not hold any material investments in APUC.

(f) | Cash flows

The Company expects to contribute $24,140 to its pension plans and $5,736 to its post-employment benefit plans in 2020.
The expected benefit payments over the next ten years are as follows:

| 2020 |  | 2021 |  | 2022 |  | 2023 |  | 2024 |  | 2025—2029
Pension plan | $ | 34,461 |  |  | $ | 34,385 |  |  | $ | 35,383 |  |  | $ | 36,897 |  |  | $ | 37,848 |  |  | $ | 192,648 |
OPEB | 7,469 |  |  | 7,867 |  |  | 8,379 |  |  | 8,903 |  |  | 9,361 |  |  | 52,864 |

Notes to the Consolidated Financial Statements – APUC 2019 Annual Report | 99

Algonquin Power & Utilities Corp.
Notes to the Consolidated Financial Statements
December 31, 2019 and 2018
(in thousands of U.S. dollars, except as noted and per share amounts)

11.Other assets
Other assets consist of the following:

| 2019 |  | 2018
Restricted cash | $ | 24,787 |  |  | $ | 18,954 |
OPEB plan assets (note 10(a)) | 8,437 |  |  | 3,161 |
Atlantica related prepaid amount (note 8(a)) | 8,844 |  |  | — |
Long-term deposits | 6,319 |  |  | 1,207 |
Income taxes recoverable | 4,416 |  |  | 1,961 |
Deferred financing costs | 5,477 |  |  | 4,449 |
Other | 8,192 |  |  | 4,967 |
| $ | 66,472 |  |  | $ | 34,699 |
Less: current portion | (7,764 | ) |  | (6,115 | )
| $ | 58,708 |  |  | $ | 28,584 |

12.Other long-term liabilities
Other long-term liabilities consist of the following:

| 2019 |  | 2018
Advances in aid of construction (a) | $ | 60,828 |  |  | $ | 63,703 |
Environmental remediation obligation (b) | 58,061 |  |  | 55,621 |
Asset retirement obligations (c) | 53,879 |  |  | 43,291 |
Customer deposits (d) | 31,946 |  |  | 29,974 |
Unamortized investment tax credits (e) | 18,234 |  |  | 17,491 |
Deferred credits (f) | 18,952 |  |  | 42,711 |
Preferred shares, Series C (g) | 13,793 |  |  | 13,418 |
Lease liabilities (note 1(q)) | 9,695 |  |  | 3,436 |
Other (h) | 35,952 |  |  | 28,360 |
| $ | 301,340 |  |  | $ | 298,005 |
Less: current portion | (57,939 | ) |  | (42,337 | )
| $ | 243,401 |  |  | $ | 255,668 |

(a) | Advances in aid of construction

The Company’s regulated utilities have various agreements with real estate development companies (the “developers”) conducting business within the Company’s utility service territories, whereby funds are advanced to the Company by the developers to assist with funding some or all of the costs of the development.
In many instances, developer advances can be subject to refund, but the refund is non-interest bearing. Refunds of developer advances are made over periods generally ranging from 5 to 40 years. Advances not refunded within the prescribed period are usually not required to be repaid. After the prescribed period has lapsed, any remaining unpaid balance is transferred to contributions in aid of construction and recorded as an offsetting amount to the cost of property, plant and equipment. In 2019, $5,465 (2018 - $3,687) was transferred from advances in aid of construction to contributions in aid of construction.

(b) | Environmental remediation obligation

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

Notes to the Consolidated Financial Statements – APUC 2019 Annual Report | 100

Algonquin Power & Utilities Corp.
Notes to the Consolidated Financial Statements
December 31, 2019 and 2018
(in thousands of U.S. dollars, except as noted and per share amounts)

12.Other long-term liabilities (continued)

(b) | Environmental remediation obligation (continued)

The Company estimates the remaining undiscounted, unescalated cost of these MGP-related environmental cleanup activities will be $58,484 (2018 - $59,181), which at discount rates ranging from 1.7% to 2.1% represents the recorded accrual of $58,061 as of December 31, 2019 (2018 - $55,621). Approximately $36,382 is expected to be incurred over the next four years, with the balance of cash flows to be incurred over the following 31 years.
Changes in the environmental remediation obligation are as follows:

| 2019 |  | 2018
Opening balance | $ | 55,621 |  |  | $ | 54,322 |
Remediation activities | (1,678 | ) |  | (2,163 | )
Accretion | 1,065 |  |  | 1,479 |
Changes in cash flow estimates | 981 |  |  | 4,051 |
Revision in assumptions | 2,072 |  |  | (2,068 | )
Closing balance | $ | 58,061 |  |  | $ | 55,621 |

By rate orders, the Regulator provided for the recovery of actual expenditures for site investigation and remediation over a period of 7 years and accordingly, as of December 31, 2019, the Company has reflected a regulatory asset of $82,300 (2018 - $82,295) for the MGP and related sites (note 7(a)).

(c) | Asset retirement obligations

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

| 2019 |  | 2018
Opening balance | $ | 43,291 |  |  | $ | 44,166 |
Obligation assumed from business acquisition and constructed projects | 3,226 |  |  | 225 |
Retirement activities | (443 | ) |  | (5,130 | )
Accretion | 2,148 |  |  | 1,974 |
Change in cash flow estimates | 5,657 |  |  | 2,056 |
Closing balance | $ | 53,879 |  |  | $ | 43,291 |

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

(d) | Customer deposits

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

(e) | Unamortized investment tax credits

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

Notes to the Consolidated Financial Statements – APUC 2019 Annual Report | 101

Algonquin Power & Utilities Corp.
Notes to the Consolidated Financial Statements
December 31, 2019 and 2018
(in thousands of U.S. dollars, except as noted and per share amounts)

12.Other long-term liabilities (continued)

(f) | Deferred credits

During the year, the Company settled $29,100 of contingent consideration related to the Company’s investment in Atlantica (note 8(a)), and recorded an additional $5,000 contingent consideration related to the Company’s investment in the San Antonio Water System (note 8(c)).
(g) Preferred shares, Series C
APUC has 100 redeemable Series C preferred shares issued and outstanding. Thirty-six of the Series C preferred shares are owned by related parties controlled by executives of the Company. The preferred shares are mandatorily redeemable in 2031 for C$53,400 per share and have a contractual cumulative cash dividend paid quarterly until the date of redemption based on a prescribed payment schedule indexed in proportion to the increase in CPI over the term of the shares. The Series C preferred shares are convertible into common shares at the option of the holder and the Company, at any time after May 20, 2031 and before June 19, 2031, at a conversion price of C$53,400 per share.
As these shares are mandatorily redeemable for cash, they are classified as liabilities in the consolidated financial statements. The Series C preferred shares are accounted for under the effective interest method, resulting in accretion of interest expense over the term of the shares. Dividend payments are recorded as a reduction of the Series C preferred share carrying value.

Estimated dividend payments due in the next five years and dividend and redemption payments thereafter are as follows:
2020 | $ | 1,035 |
2021 | 1,050 |
2022 | 1,070 |
2023 | 1,243 |
2024 | 1,454 |
Thereafter to 2031 | 9,439 |
Redemption amount | 4,111 |
| $ | 19,402 |
Less: amounts representing interest | (5,609 | )
| $ | 13,793 |
Less current portion | (1,035 | )
| $ | 12,758 |

(h) | Other

Convertible debentures
As at December 31, 2019, the carrying value of the convertible debentures was $342 (2018 - $470). The convertible debentures mature on March 31, 2026 and bear interest at an annual rate of 0% per C$1,000 principal amount of convertible debentures. The debentures are convertible at a price of C$10.60 per share into up to 44,130 common shares. During the year ended December 31, 2019, $148 (2018 - $447) of principal converted to 19,429 (2018 - 56,926) common shares of the Company (note 13).

Notes to the Consolidated Financial Statements – APUC 2019 Annual Report | 102

Algonquin Power & Utilities Corp.
Notes to the Consolidated Financial Statements
December 31, 2019 and 2018
(in thousands of U.S. dollars, except as noted and per share amounts)

13. | Shareholders’ capital

(a) | Common shares

Number of common shares

|  | 2019 |  | 2018
Common shares, beginning of year |  | 488,851,433 |  |  | 431,765,935 |
Public offering (a)(i) and (a)(ii) |  | 28,009,341 |  |  | 50,041,624 |
Dividend reinvestment plan (a)(iii) |  | 6,068,465 |  |  | 5,880,843 |
Exercise of share-based awards (c) |  | 1,274,655 |  |  | 1,106,105 |
Conversion of convertible debentures (note 12(h)) |  | 19,429 |  |  | 56,926 |
Common shares, end of year |  | 524,223,323 |  |  | 488,851,433 |

Authorized
APUC is authorized to issue an unlimited number of common shares. The holders of the common shares are entitled to dividends if, as and when declared by the Board of Directors (the “Board”); to one vote per share at meetings of the holders of common shares; and upon liquidation, dissolution or winding up of APUC to receive pro rata the remaining property and assets of APUC, subject to the rights of any shares having priority over the common shares.
The Company has a shareholders’ rights plan (the “Rights Plan”), which expires in 2022. Under the Rights Plan, one right is issued with each issued share of the Company. The rights remain attached to the shares and are not exercisable or separable unless one or more certain specified events occur. If a person or group acting in concert acquires 20 percent or more of the outstanding shares (subject to certain exceptions) of the Company, the rights will entitle the holders thereof (other than the acquiring person or group) to purchase shares at a 50 percent discount from the then-current market price. The rights provided under the Rights Plan are not triggered by any person making a “Permitted Bid”, as defined in the Rights Plan.

(i) | Public offering

In October 2019, APUC issued 26,252,542 common shares at $13.50 per share pursuant to a public offering for proceeds of $354,409 before issuance costs of $14,418.
On December 20, 2018, APUC issued 12,536,350 common shares at $10.09 (C$13.76) per share pursuant to a public offering for proceeds of $126,485 (C$172,500) before issuance costs of $366 (C$492).
On April 24, 2018, APUC issued 37,505,274 common shares at $9.23 (C$11.85) per share pursuant to a public offering for gross proceeds of $346,458 (C$444,437) before issuance costs of $590 (C$765).

(ii) | At-the-market equity program

On February 28, 2019, APUC established an at-the-market equity program (“ATM program”) that allows the Company to issue up to $250,000 of common shares from treasury to the public from time to time, at the Company’s discretion, at the prevailing market price when issued on the TSX, the NYSE, or any other existing trading market for the common shares of the Company in Canada or the United States. During the year, the Company issued 1,756,799 common shares under the ATM program at an average price of $12.54 per common share for gross proceeds of $22,034 ($21,704 net of commissions). Other related costs, primarily related to the establishment of the ATM program, were $2,122.

(iii) | Dividend reinvestment plan

The Company has a common shareholder dividend reinvestment plan, which provides an opportunity for shareholders to reinvest dividends for the purpose of purchasing common shares. Additional common shares acquired through the reinvestment of cash dividends are purchased in the open market or are issued by APUC at a discount of up to 5% from the average market price, all as determined by the Company from time to time. Subsequent to year-end, APUC issued an additional 1,244,696 common shares under the dividend reinvestment plan.

Notes to the Consolidated Financial Statements – APUC 2019 Annual Report | 103

Algonquin Power & Utilities Corp.
Notes to the Consolidated Financial Statements
December 31, 2019 and 2018
(in thousands of U.S. dollars, except as noted and per share amounts)

13. | Shareholders’ capital (continued)

(b) | Preferred shares

APUC is authorized to issue an unlimited number of preferred shares, issuable in one or more series, containing terms and conditions as approved by the Board.
The Company has the following Series A and Series D preferred shares issued and outstanding as at December 31, 2019 and 2018:

Preferred shares | Number of shares |  | Price per share |  | Carrying amount C$ |  | Carrying amount $
Series A | 4,800,000 |  |  | C$ | 25 |  |  | C$ | 116,546 |  |  | $ | 100,463 |
Series D | 4,000,000 |  |  | C$ | 25 |  |  | C$ | 97,259 |  |  | $ | 83,836 |
|  |  |  |  |  |  |  | $ | 184,299 |

The holders of Series A and Series D preferred shares had the right to convert their shares into cumulative floating rate preferred shares, Series B and Series E, respectively, subject to certain conditions, on December 31, 2018 and March 31, 2019, respectively, and every fifth year thereafter. Neither the Series A nor the Series B preferred shares were converted on December 31, 2018 and March 31, 2019 respectively.
The holders of Series A preferred shares are entitled to receive quarterly fixed cumulative preferential cash dividends, if, as and when declared by the Board. The dividend for each year up to, but excluding, December 31, 2018 was an annual amount of C$1.125 per share. The dividend rate for the five-year period from and including December 31, 2018 to but excluding December 31, 2023 will be $1.2905. The Series A dividend rate will reset on December 31, 2023 and every five years thereafter at a rate equal to the then five-year Government of Canada bond yield plus 2.94%. The Series A preferred shares are redeemable at C$25 per share at the option of the Company on December 31, 2023 and every fifth year thereafter.
The holders of Series D preferred shares are entitled to receive fixed cumulative preferential dividends as and when declared by the Board at an annual amount of C$1.25 per share for each year up to, but excluding, March 31, 2019. The dividend for the five-year period from and including March 31, 2019 to, but excluding, March 31, 2024 will be C$1.2728. The Series D dividend will reset on March 31, 2024 and every five years thereafter at a rate equal to the then five-year Government of Canada bond plus 3.28%. The Series D preferred shares are redeemable at C$25 per share at the option of the Company on March 31, 2024 and every fifth year thereafter.
The Company has 100 redeemable Series C preferred shares issued and outstanding. The mandatorily redeemable Series C preferred shares are recorded as a liability on the consolidated balance sheets as they are mandatorily redeemable for cash (note 12(g)).

(c) | Share-based compensation

For the year ended December 31, 2019, APUC recorded $10,553 (2018 - $9,458) in total share-based compensation expense detailed as follows:

| 2019 |  | 2018
Share options | $ | 1,288 |  |  | $ | 2,054 |
Director deferred share units | 798 |  |  | 714 |
Employee share purchase | 322 |  |  | 312 |
Performance and restricted share units | 8,145 |  |  | 6,378 |
Total share-based compensation | $ | 10,553 |  |  | $ | 9,458 |

Notes to the Consolidated Financial Statements – APUC 2019 Annual Report | 104

Algonquin Power & Utilities Corp.
Notes to the Consolidated Financial Statements
December 31, 2019 and 2018
(in thousands of U.S. dollars, except as noted and per share amounts)

13. | Shareholders’ capital (continued)

(c) | Share-based compensation (continued)

The compensation expense is recorded as part of administrative expenses in the consolidated statements of operations. The portion of share-based compensation costs capitalized as cost of construction is insignificant.
As of December 31, 2019, total unrecognized compensation costs related to non-vested options and PSUs were $1,252 and $12,750, respectively, and are expected to be recognized over a period of 1.68 and 1.86 years, respectively.

(i) | Share option plan

The Company’s share option plan (the “Plan”) permits the grant of share options to officers, directors, employees and selected service providers. The aggregate number of shares that may be reserved for issuance under the Plan must not exceed 8% of the number of shares outstanding at the time the options are granted.
The number of shares subject to each option, the option price, the expiration date, the vesting and other terms and conditions relating to each option shall be determined by the Board (or the compensation committee of the Board (“Compensation Committee”)) from time to time. Dividends on the underlying shares do not accumulate during the vesting period. Option holders may elect to surrender any portion of the vested options that is then exercisable in exchange for the “In-the-Money Amount”. In accordance with the Plan, the “In-The-Money Amount” represents the excess, if any, of the market price of a share at such time over the option price, in each case such “In-the-Money Amount” being payable by the Company in cash or shares at the election of the Company. As the Company does not expect to settle these instruments in cash, these options are accounted for as equity awards.
The Compensation Committee may accelerate the vesting of the unvested options then held by the optionee at the Compensation Committee’s discretion. In the event that the Company restates its financial results, any unpaid or unexercised options may be cancelled at the discretion of the Compensation Committee in accordance with the terms of the Company’s clawback policy.
The estimated fair value of options, including the effect of estimated forfeitures, is recognized as expense on a straight-line basis over the options’ vesting periods while ensuring that the cumulative amount of compensation cost recognized at least equals the value of the vested portion of the award at that date. The Company determines the fair value of options granted using the Black-Scholes option-pricing model. The risk-free interest rate is based on the zero-coupon Canada Government bond with a similar term to the expected life of the options at the grant date. Expected volatility was estimated based on the historical volatility of the Company’s shares. The expected life was based on experience to date. The dividend yield rate was based upon recent historical dividends paid on APUC shares.
The following assumptions were used in determining the fair value of share options granted:

| 2019 |  | 2018
Risk-free interest rate | 1.9 | % |  | 2.1 | %
Expected volatility | 20 | % |  | 21 | %
Expected dividend yield | 4.3 | % |  | 4.8 | %
Expected life | 5.50 years |  |  | 5.50 years |
Weighted average grant date fair value per option | C$ | 1.66 |  |  | C$ | 1.41 |

Notes to the Consolidated Financial Statements – APUC 2019 Annual Report | 105

Algonquin Power & Utilities Corp.
Notes to the Consolidated Financial Statements
December 31, 2019 and 2018
(in thousands of U.S. dollars, except as noted and per share amounts)

13. | Shareholders’ capital (continued)

(c) | Share-based compensation (continued)

(i) | Share option plan (continued)

Share option activity during the years is as follows:

| Number of awards |  | Weighted average exercise price |  | Weighted average remaining contractual term (years) |  | Aggregate intrinsic value
Balance, January 1, 2018 | 6,738,856 |  |  | C$ | 11.18 |  |  | 6.32 |  |  | C$ | 19,380 |
Granted | 1,166,717 |  |  | 12.80 |  |  | 8.00 |  |  | — |
Exercised | (1,589,211 | ) |  | 10.66 |  |  | 5.02 |  |  | 5,059 |
Forfeited | (23,720 | ) |  | 12.80 |  |  | — |  |  | — |
Balance, December 31, 2018 | 6,292,642 |  |  | C$ | 11.61 |  |  | 5.75 |  |  | C$ | 13,342 |
Granted | 1,113,775 |  |  | 14.96 |  |  | 8.00 |  |  | — |
Exercised | (3,882,505 | ) |  | 11.23 |  |  | 4.45 |  |  | 6,225 |
Forfeited | — |  |  | — |  |  | — |  |  | — |
Balance, December 31, 2019 | 3,523,912 |  |  | C$ | 13.09 |  |  | 5.87 |  |  | C$ | 18,609 |
Exercisable, December 31, 2019 | 1,735,241 |  |  | C$ | 12.57 |  |  | 5.43 |  |  | C$ | 14,559 |

Subsequent to year-end, on February 19, 2020, 394,939 stock options were exercised at a weighted average price of C$12.77 in exchange for 115,517 common shares issued from treasury, and 279,422 options settled at their cash value as payment for the exercise price and tax withholdings related to the exercise of the options.

(ii) | Employee share purchase plan

Under the Company’s employee share purchase plan (“ESPP”), eligible employees may have a portion of their earnings withheld to be used to purchase the Company’s common shares. The Company will match 20% of the employee contribution amount for the first five thousand dollars per employee contributed annually and 10% of the employee contribution amount for contributions over five thousand dollars up to ten thousand dollars annually. Common shares purchased through the Company match portion shall not be eligible for sale by the participant for a period of one year following the purchase date on which such shares were acquired. At the Company’s option, the common shares may be (i) issued to participants from treasury at the average share price or (ii) acquired on behalf of participants by purchases through the facilities of the TSX or NYSE by an independent broker. The aggregate number of common shares reserved for issuance from treasury by APUC under the ESPP shall not exceed 2,000,000 common shares.
The Company uses the fair value based method to measure the compensation expense related to the Company’s contribution. For the year ended December 31, 2019, a total of 253,538 common shares (2018 - 252,698) were issued to employees under the ESPP.

(iii) | Director’s deferred share units

Under the Company’s deferred share unit plan, non-employee directors of the Company may elect annually to receive all or any portion of their compensation in DSUs in lieu of cash compensation. Directors’ fees are paid on a quarterly basis and at the time of each payment of fees, the applicable amount is converted to DSUs. A DSU has a value equal to one of the Company’s common shares. Dividends accumulate in the DSU account and are converted to DSUs based on the market value of the shares on that date. DSUs cannot be redeemed until the director retires, resigns, or otherwise leaves the Board. The DSUs provide for settlement in cash or shares at the election of the Company. As the Company does not expect to settle these instruments in cash, these options are accounted for as equity awards. As of December 31, 2019, 460,418 (2018 - 380,656) DSUs were outstanding pursuant to the election of the directors to defer a percentage of their director’s fee in the form of DSUs. The aggregate number of common shares reserved for issuance from treasury by APUC under the DSU plan shall not exceed 1,000,000 common shares.

Notes to the Consolidated Financial Statements – APUC 2019 Annual Report | 106

Algonquin Power & Utilities Corp.
Notes to the Consolidated Financial Statements
December 31, 2019 and 2018
(in thousands of U.S. dollars, except as noted and per share amounts)

13. | Shareholders’ capital (continued)

(c) | Share-based compensation (continued)

(iv) | Performance and restricted share units

The Company offers a PSU and RSU plan to its employees as part of the Company’s long-term incentive program. PSUs have been granted annually for three-year overlapping performance cycles. The PSUs vest at the end of the three-year cycle and will be calculated based on established performance criteria. At the end of the three-year performance periods, the number of common shares issued can range from 2.0% to 237% of the number of PSUs granted. RSU vesting conditions and dates vary by grant and are outlined in each award letter. RSUs are not subject to performance criteria. Dividends accumulating during the vesting period are converted to PSUs and RSUs based on the market value of the shares on that date and are recorded in equity as the dividends are declared. None of these PSUs or RSUs have voting rights. Any PSUs or RSUs not vested at the end of a performance period will expire. The PSUs and RSUs provide for settlement in cash or shares at the election of the Company. As the Company does not expect to settle these instruments in cash, these units are accounted for as equity awards. The aggregate number of common shares reserved for issuance from treasury by APUC under the PSU and RSU Plan shall not exceed 7,000,000 common shares.
Compensation expense associated with PSUs is recognized rateably over the performance period. Achievement of the performance criteria is estimated at the consolidated balance sheet dates. Compensation cost recognized is adjusted to reflect the performance conditions estimated to date.
A summary of the PSUs and RSUs follows:

| Number of awards |  | Weighted average grant-date fair value |  | Weighted average remaining contractual term (years) |  | Aggregate intrinsic value
Balance, January 1, 2018 | 955,028 |  |  | C$ | 12.30 |  |  | 1.84 |  |  | C$ | 13,428 |
Granted, including dividends | 791,524 |  |  | 12.41 |  |  | 2.00 |  |  | 10,098 |
Exercised | (285,551 | ) |  | 10.02 |  |  | — |  |  | 3,691 |
Forfeited | (68,869 | ) |  | 13.02 |  |  | — |  |  | — |
Balance, December 31, 2018 | 1,392,132 |  |  | C$ | 12.75 |  |  | 1.60 |  |  | C$ | 19,114 |
Granted, including dividends | 1,471,442 |  |  | 14.69 |  |  | 2.00 |  |  | 16,302 |
Exercised | (344,340 | ) |  | 11.55 |  |  | — |  |  | 5,148 |
Forfeited | (107,191 | ) |  | 13.84 |  |  | — |  |  | — |
Balance, December 31, 2019 | 2,412,043 |  |  | C$ | 14.00 |  |  | 1.86 |  |  | C$ | 44,309 |
Exercisable, December 31, 2019 | 743,787 |  |  | C$ | 13.21 |  |  | — |  |  | C$ | 13,663 |

(v) | Bonus deferral RSUs

During 2018, the Company introduced a new bonus deferral RSU program to certain of its employees. Eligible employees have the option to receive a portion or all of their annual bonus payment in RSUs in lieu of cash. The RSUs provide for settlement in shares, and therefore these options are accounted for as equity awards. The RSUs granted are 100% vested and therefore, compensation expense associated with RSUs is recognized immediately upon issuance.

Notes to the Consolidated Financial Statements – APUC 2019 Annual Report | 107

Algonquin Power & Utilities Corp.
Notes to the Consolidated Financial Statements
December 31, 2019 and 2018
(in thousands of U.S. dollars, except as noted and per share amounts)

13. | Shareholders’ capital (continued)

(c) | Share-based compensation (continued)

(vi) | Bonus deferral RSUs

A summary of the bonus deferral RSUs follows:

| Number of awards |  | Weighted average grant-date fair value |  | Aggregate intrinsic value
Balance, December 31, 2017 | — |  |  | C$ | — |  |  | C$ | — |
Granted, including dividends | 131,611 |  |  | 12.82 |  |  | 1,683 |
Exercised | (4,545 | ) |  | 12.82 |  |  | 61 |
Balance, December 31, 2018 | 127,066 |  |  | C$ | 12.82 |  |  | C$ | 1,745 |
Granted, including dividends | 135,324 |  |  | 15.40 |  |  | 2,084 |
Balance and exercisable, December 31, 2019 | 262,390 |  |  | C$ | 14.15 |  |  | C$ | 4,820 |

14.Accumulated other comprehensive income (loss)
AOCI consists of the following balances, net of tax:

| Foreign currency cumulative translation |  | Unrealized gain on cash flow hedges |  | Pension and post-employment actuarial changes |  | Total
Balance, January 1, 2018 | $ | (47,701 | ) |  | $ | 55,366 |  |  | $ | (10,457 | ) |  | $ | (2,792 | )
Adoption of ASU 2018-02 on tax effects in AOCI | — |  |  | 11,657 |  |  | (1,032 | ) |  | 10,625 |
Other comprehensive income (loss) | (27,969 | ) |  | 1,567 |  |  | 2,046 |  |  | (24,356 | )
Amounts reclassified from AOCI to the consolidated statement of operations | — |  |  | (4,257 | ) |  | (86 | ) |  | (4,343 | )
Net current period OCI | $ | (27,969 | ) |  | $ | (2,690 | ) |  | $ | 1,960 |  |  | $ | (28,699 | )
OCI attributable to the non-controlling interests | 1,481 |  |  | — |  |  | — |  |  | 1,481 |
Net current period OCI attributable to shareholders of APUC | $ | (26,488 | ) |  | $ | (2,690 | ) |  | $ | 1,960 |  |  | $ | (27,218 | )
Balance, December 31, 2018 | $ | (74,189 | ) |  | $ | 64,333 |  |  | $ | (9,529 | ) |  | $ | (19,385 | )
Adoption of ASU 2017-12 on hedging (note 2(a)) | — |  |  | 186 |  |  | — |  |  | 186 |
Other comprehensive income (loss) | 7,795 |  |  | 19,177 |  |  | (7,999 | ) |  | 18,973 |
Amounts reclassified from AOCI to the consolidated statement of operations | — |  |  | (8,597 | ) | — |  | 1,490 |  |  | (7,107 | )
Net current period OCI | $ | 7,795 |  |  | $ | 10,580 |  |  | $ | (6,509 | ) |  | $ | 11,866 |
OCI attributable to the non-controlling interests | (2,428 | ) |  | — |  |  | — |  |  | (2,428 | )
Net current period OCI attributable to shareholders of APUC | $ | 5,367 |  |  | $ | 10,580 |  |  | $ | (6,509 | ) |  | $ | 9,438 |
Balance, December 31, 2019 | $ | (68,822 | ) |  | $ | 75,099 |  |  | $ | (16,038 | ) |  | $ | (9,761 | )

Amounts reclassified from AOCI for unrealized gain (loss) on cash flow hedges affected revenue from non-regulated energy sales while those for pension and post-employment actuarial changes affected pension and post-employment non-service costs.

Notes to the Consolidated Financial Statements – APUC 2019 Annual Report | 108

Algonquin Power & Utilities Corp.
Notes to the Consolidated Financial Statements
December 31, 2019 and 2018
(in thousands of U.S. dollars, except as noted and per share amounts)

15. | Dividends

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

| 2019 |  | 2018
| Dividend |  | Dividend per share |  | Dividend |  | Dividend per share
Common shares | $ | 277,835 |  |  | $ | 0.5512 |  |  | $ | 235,440 |  |  | $ | 0.5011 |
Series A preferred shares | C$ | 6,194 |  |  | C$ | 1.2905 |  |  | C$ | 5,400 |  |  | C$ | 1.1250 |
Series D preferred shares | C$ | 5,068 |  |  | C$ | 1.2671 |  |  | C$ | 5,000 |  |  | C$ | 1.2500 |

16.Related party transactions
(a)Equity-method investments
The Company provides administrative and development services to its equity-method investees and is reimbursed for incurred costs. To that effect, during 2019, the Company charged its equity-method investees $12,374 (2018 - $11,390).
On December 30, 2019, the Company sold its interest in AWUSA to a joint venture entity in exchange for a note receivable of $30,293 (note 8(c)). No gain or loss was recognized on the sale. For the year, APUC recorded interest income of $6,007, and a fair value loss of $6,007 on its investment in the joint venture.
During the year, the Company sold the Sugar Creek Wind Project to AAGES Sugar Creek in exchange for a note receivable of $21,107, subject to certain adjustments. No gain was recorded on deconsolidation of the Sugar Creek net assets. However, an amount of $15,765, or $11,412, net of tax, was reclassified from AOCI into earnings as a result of the discontinuation of hedge accounting on energy derivatives put in place early in the development of Sugar Creek (note 24(b)(ii)).
During the year, the Company entered into an enhanced cooperation agreement with Atlantica to, among other things, provide a framework for evaluating mutually advantageous transactions. For a period of one year from the date of the agreement, Atlantica has an exclusive right of first offer for interests in certain Renewable Energy assets.
(b)Redeemable non-controlling interest held by related party
Redeemable non-controlling interest held by related party represents a preference share in a consolidated subsidiary of the Company acquired by AAGES B.V. in 2018 for $305,000 (note 8(a)). Redemption is not considered probable as at December 31, 2019. The Company incurred non-controlling interest attributable to AAGES B.V. of $16,482 (2018 - $2,622) and recorded distributions of $18,241 (2018 - $nil) during the year (note 17).
(c)Non-controlling interest held by related party
Non-controlling interest held by related party represents interest in a consolidated subsidiary of the Company acquired by AYES Canada in May 2019 for $96,752 (note 8(b)). The Company recorded distributions of $26,465 during the year.
(d)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.

Notes to the Consolidated Financial Statements – APUC 2019 Annual Report | 109

Algonquin Power & Utilities Corp.
Notes to the Consolidated Financial Statements
December 31, 2019 and 2018
(in thousands of U.S. dollars, except as noted and per share amounts)

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

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

| 2019 |  | 2018
HLBV and other adjustments attributable to: |  |  |
Non-controlling interests - tax equity partnership units | $ | (55,963 | ) |  | $ | (103,150 | )
Non-controlling interests - redeemable tax equity partnership units | (9,006 | ) |  | (7,545 | )
Other net earnings attributable to: |  |  |
Non-controlling interests | 2,553 |  |  | 2,174 |
| $ | (62,416 | ) |  | $ | (108,521 | )
Redeemable non-controlling interest, held by related party | 16,482 |  |  | 2,622 |
Net effect of non-controlling interests | $ | (45,934 | ) |  | $ | (105,899 | )

The non-controlling tax equity investors (“tax equity partnership units”) in the Company’s U.S. wind power and solar power generating facilities are entitled to allocations of earnings, tax attributes and cash flows in accordance with contractual agreements. The share of earnings attributable to the non-controlling interest holders in these subsidiaries is calculated using the HLBV method of accounting as described in note 1(s).
The terms of the arrangement refer to the tax rate in effect when the benefits are delivered. As such, the U.S. federal corporate tax rate of 35% was used to calculate HLBV as at December 31, 2017. The reduced U.S. federal corporate tax rate of 21% and other certain measures included in the Tax Act effective January 1, 2018 were reflected in the calculation of HLBV in 2018. The changes accelerated HLBV income from future years to the first quarter of 2018 in the amount of $55,900.
Non-controlling interests
As of December 31, 2019, non-controlling interests of $457,834 (2018 - $519,896) include partnership units held by tax equity investors in certain U.S. wind power and solar generating facilities of $457,000 (2018 - 519,100) and other non-controlling interests of $834 (2018 - $796). Contributions from tax equity investors of $15,250 were received for the Great Bay Solar I Facility in 2018 (note 3(g)).
Non-controlling interest held by related party
Non-controlling interest was issued to AYES Canada in May 2019 for $96,752 (note 8(b)). The balance as of December 31, 2019 was $73,707.
Redeemable non-controlling interests
Non-controlling interests in subsidiaries that are redeemable upon the occurrence of uncertain events not solely within APUC’s control are classified as temporary equity on the consolidated balance sheets. If the redemption is probable or currently redeemable, the Company records the instruments at their redemption value. Redemption is not considered probable as of December 31, 2019. Changes in redeemable non-controlling interests are as follows:

| Redeemable non-controlling interests held by related party |  | Redeemable non-controlling interests
| 2019 |  | 2018 |  | 2019 |  | 2018
Opening balance | $ | 307,622 |  |  | $ | — |  |  | $ | 33,364 |  |  | $ | 41,553 |
Net effect from operations | 16,482 |  |  | 2,622 |  |  | (9,006 | ) |  | (7,545 | )
Contributions, net of costs | — |  |  | 305,000 |  |  | 3,403 |  |  | — |
Dividends and distributions declared | (18,241 | ) |  | — |  |  | (1,848 | ) |  | (644 | )
Closing balance | $ | 305,863 |  |  | $ | 307,622 |  |  | $ | 25,913 |  |  | $ | 33,364 |

During 2019, contributions from tax equity partnership investors of $3,403 were received for the Turquoise Solar Facility (note 3(b)). During 2018, contributions of $305,000 were received from AAGES B.V. for a preference share of AY Holdings (note 8(a)).

Notes to the Consolidated Financial Statements – APUC 2019 Annual Report | 110

Algonquin Power & Utilities Corp.
Notes to the Consolidated Financial Statements
December 31, 2019 and 2018
(in thousands of U.S. dollars, except as noted and per share amounts)

18. | Income taxes

The provision for income taxes in the consolidated statements of operations represents an effective tax rate different than the Canadian enacted statutory rate of 26.5% (2018 - 26.5%). The differences are as follows:

| 2019 |  | 2018
Expected income tax expense at Canadian statutory rate | $ | 147,093 |  |  | $ | 35,102 |
Increase (decrease) resulting from: |  |  |
Effect of differences in tax rates on transactions in and within foreign jurisdictions and change in tax rates | (27,703 | ) |  | (28,064 | )
Adjustments from investments carried at fair value | (60,730 | ) |  | 25,870 |
Non-controlling interests share of income | 16,991 |  |  | 29,637 |
Non-deductible acquisition costs | 2,500 |  |  | 4,267 |
Tax credits | (9,332 | ) |  | (1,419 | )
Adjustment relating to prior periods | (1,240 | ) |  | 3,673 |
U.S. Tax reform and related deferred tax adjustments (1) | — |  |  | (18,363 | )
Other | 2,538 |  |  | 2,669 |
Income tax expense | $ | 70,117 |  |  | $ | 53,372 |

(1) In 2017, the Tax Cuts and Jobs Act (“Tax Act”) implemented significant changes to U.S. tax legislation, including a reduction in the U.S. federal corporate income tax from 35% to 21%, effective January 1, 2018. The Company’s U.S. entities were required to remeasure their deferred tax assets and liabilities at the new corporate income tax rate as at the date of enactment. In 2018, an adjustment related to the implementation of U.S. Tax Reform resulted in a non-cash accounting benefit of $18,363, which was recorded in the Company’s 2018 consolidated statement of operations.
For the years ended December 31, 2019 and 2018, earnings before income taxes consist of the following:

| 2019 |  | 2018
Canada | $ | 351,908 |  |  | $ | (109,537 | )
U.S. | 203,159 |  |  | 241,998 |
| $ | 555,067 |  |  | $ | 132,461 |

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

| Current |  | Deferred |  | Total
Year ended December 31, 2019 |  |  |  |  |
Canada | $ | 6,695 |  |  | $ | 17,607 |  |  | $ | 24,302 |
United States | 9,736 |  |  | 36,079 |  |  | 45,815 |
| $ | 16,431 |  |  | $ | 53,686 |  |  | $ | 70,117 |
Year ended December 31, 2018 |  |  |  |  |
Canada | $ | 2,872 |  |  | $ | (14,197 | ) |  | $ | (11,325 | )
United States | 8,475 |  |  | 56,222 |  |  | 64,697 |
| $ | 11,347 |  |  | $ | 42,025 |  |  | $ | 53,372 |

Notes to the Consolidated Financial Statements – APUC 2019 Annual Report | 111

Algonquin Power & Utilities Corp.
Notes to the Consolidated Financial Statements
December 31, 2019 and 2018
(in thousands of U.S. dollars, except as noted and per share amounts)

18. | Income taxes (continued)

The tax effect of temporary differences between the financial statement carrying amounts of assets and liabilities and their respective tax bases that give rise to significant portions of the deferred tax assets and deferred tax liabilities as of December 31, 2019 and 2018 are presented below:

| 2019 |  | 2018
Deferred tax assets: |  |  |
Non-capital loss, investment tax credits, currently non-deductible interest expenses, and financing costs | $ | 382,448 |  |  | $ | 329,099 |
Pension and OPEB | 54,113 |  |  | 48,586 |
Environmental obligation | 15,541 |  |  | 14,790 |
Regulatory liabilities | 160,200 |  |  | 161,560 |
Other | 59,103 |  |  | 45,193 |
Total deferred income tax assets | $ | 671,405 |  |  | $ | 599,228 |
Less: valuation allowance | (29,447 | ) |  | (28,018 | )
Total deferred tax assets | $ | 641,958 |  |  | $ | 571,210 |
Deferred tax liabilities: |  |  |
Property, plant and equipment | $ | 707,185 |  |  | $ | 653,962 |
Outside basis in partnership | 235,063 |  |  | 167,659 |
Regulatory accounts | 145,852 |  |  | 113,758 |
Other | 14,811 |  |  | 7,561 |
Total deferred tax liabilities | $ | 1,102,911 |  |  | $ | 942,940 |
Net deferred tax liabilities | $ | (460,953 | ) |  | $ | (371,730 | )
Consolidated balance sheets classification: |  |  |
Deferred tax assets | $ | 30,585 |  |  | $ | 72,415 |
Deferred tax liabilities | (491,538 | ) |  | (444,145 | )
Net deferred tax liabilities | $ | (460,953 | ) |  | $ | (371,730 | )

The valuation allowance for deferred tax assets as at December 31, 2019 was $29,447 (2018 - $28,018). The valuation allowance primarily relates to operating losses that, in the judgment of management, are not more likely than not to be realized. In assessing the realizability 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. The ultimate realization of deferred tax assets is dependent upon the generation of future taxable income during the periods in which those temporary differences become deductible. Management considers the scheduled reversal of deferred tax liabilities (including the impact of available carryback and carryforward periods), projected future taxable income, and tax-planning strategies in making this assessment.
As of December 31, 2019, the Company had non-capital losses carried forward available to reduce future years’ taxable income, which expire as follows:

Year of expiry | Non-capital loss carryforwards
2020 and onwards | $ | 1,091,322 |

The Company has provided for deferred income taxes for the estimated tax cost of distributed earnings of certain of its subsidiaries. Deferred income taxes have not been provided on approximately $370,682 of undistributed earnings of certain foreign subsidiaries, as the Company has concluded that such earnings are indefinitely reinvested and should not give rise to additional tax liabilities. A determination of the amount of the unrecognized tax liability relating to the remittance of such undistributed earnings is not practicable.

Notes to the Consolidated Financial Statements – APUC 2019 Annual Report | 112

Algonquin Power & Utilities Corp.
Notes to the Consolidated Financial Statements
December 31, 2019 and 2018
(in thousands of U.S. dollars, except as noted and per share amounts)

19. | Other losses

Other losses consist of the following:

| 2019 |  | 2018
Pension and other post-employment non-service costs (note 10) | $ | (17,332 | ) |  | $ | (4,990 | )
Acquisition and transition-related costs (note 3) | (11,609 | ) |  | (687 | )
Other | (15,085 | ) |  | (2,725 | )
| $ | (44,026 | ) |  | $ | (8,402 | )

20. | Basic and diluted net earnings per share

Basic and diluted earnings per share have been calculated on the basis of net earnings attributable to the common shareholders of the Company and the weighted average number of common shares and bonus deferral restricted share units outstanding. Diluted net earnings per share is computed using the weighted-average number of common shares, subscription receipts outstanding, additional shares issued subsequent to year-end under the dividend reinvestment plan, PSUs, RSUs and DSUs outstanding during the year and, if dilutive, potential incremental common shares resulting from the application of the treasury stock method to outstanding share options and additional shares issued subsequent to quarter-end under the dividend reinvestment plan. The convertible debentures (note 12(h)) are convertible into common shares at any time prior to maturity or redemption by the Company. The shares issuable upon conversion of the convertible debentures are included in diluted earnings per share.
The reconciliation of the net earnings and the weighted average shares used in the computation of basic and diluted earnings per share are as follows:

| 2019 |  | 2018
Net earnings attributable to shareholders of APUC | $ | 530,884 |  |  | $ | 184,988 |
Series A preferred shares dividend | 4,666 |  |  | 4,169 |
Series D preferred shares dividend | 3,820 |  |  | 3,858 |
Net earnings attributable to common shareholders of APUC from continuing operations – basic and diluted | $ | 522,398 |  |  | $ | 176,961 |
Weighted average number of shares |  |  |
Basic | 499,910,876 |  |  | 461,818,023 |
Effect of dilutive securities | 4,828,678 |  |  | 4,227,595 |
Diluted | 504,739,554 |  |  | 466,045,618 |

The shares potentially issuable as a result of 1,113,775 share options (2018 - 3,380,184) are excluded from this calculation as they are anti-dilutive.

Notes to the Consolidated Financial Statements – APUC 2019 Annual Report | 113

Algonquin Power & Utilities Corp.
Notes to the Consolidated Financial Statements
December 31, 2019 and 2018
(in thousands of U.S. dollars, except as noted and per share amounts)

21. | Segmented information

The Company is managed under two primary business units consisting of the Regulated Services Group and the Renewable Energy Group. The two business units are the two segments of the Company.
The Regulated Services Group, the Company’s regulated operating unit, owns and operates a portfolio of electric, natural gas, water distribution and wastewater collection utility systems and transmission operations in the United States and Canada; the Renewable Energy Group, the Company’s non-regulated operating unit, owns and operates a diversified portfolio of renewable and thermal electric generation assets in North America and internationally.
For purposes of evaluating the performance of the business units, the Company allocates the realized portion of any gains or losses on financial instruments to the specific business units. Dividend income from Atlantica and AYES Canada are included in the operations of the Renewable Energy Group while interest income from San Antonio Water System is included in the operations of the Regulated Services Group. Equity method gains and losses are included in the operations of the Regulated Services Group or Renewable Energy Group based on the nature of the activities of the investees. The change in value of investments carried at fair value and unrealized portion of any gains or losses on derivative instruments not designated in a hedging relationship are not considered in management’s evaluation of divisional performance and are therefore allocated and reported under corporate.

| Year ended December 31, 2019
| Regulated Services Group |  | Renewable Energy Group |  | Corporate |  | Total
Revenue (1)(2) | $ | 1,366,971 |  |  | $ | 257,950 |  |  | $ | — |  |  | $ | 1,624,921 |
Fuel, power and water purchased | 426,046 |  |  | 17,258 |  |  | — |  |  | 443,304 |
Net revenue | 940,925 |  |  | 240,692 |  |  | — |  |  | 1,181,617 |
Operating expenses | 396,559 |  |  | 75,209 |  |  | 221 |  |  | 471,989 |
Administrative expenses | 36,628 |  |  | 19,405 |  |  | 769 |  |  | 56,802 |
Depreciation and amortization | 194,498 |  |  | 88,825 |  |  | 981 |  |  | 284,304 |
Loss on foreign exchange | — |  |  | — |  |  | 3,146 |  |  | 3,146 |
Operating income (loss) | 313,240 |  |  | 57,253 |  |  | (5,117 | ) |  | 365,376 |
Interest expense | (101,518 | ) |  | (61,039 | ) |  | (18,931 | ) |  | (181,488 | )
Income from long-term investments | 9,334 |  |  | 104,025 |  |  | 285,733 |  |  | 399,092 |
Other income (expenses) | (32,292 | ) |  | 15,946 |  |  | (11,567 | ) |  | (27,913 | )
Earnings before income taxes | $ | 188,764 |  |  | $ | 116,185 |  |  | $ | 250,118 |  |  | $ | 555,067 |
Property, plant and equipment | $ | 4,754,373 |  |  | $ | 2,444,382 |  |  | $ | 32,909 |  |  | $ | 7,231,664 |
Investments carried at fair value | 27,072 |  |  | 1,267,075 |  |  | — |  |  | 1,294,147 |
Equity-method investees | 29,827 |  |  | 53,670 |  |  | 273 |  |  | 83,770 |
Total assets | 6,816,063 |  |  | 4,014,067 |  |  | 81,340 |  |  | 10,911,470 |
Capital expenditures | $ | 478,936 |  |  | $ | 102,396 |  |  | $ | — |  |  | $ | 581,332 |

(1) Revenue includes $22,282 related to net hedging gains from energy derivative contracts for the year ended December 31, 2019 that do not represent revenue recognized from contracts with customers.
(2) Regulated Services Group revenue includes $(4,405) related to alternative revenue programs for the year ended December 31, 2019 that do not represent revenue recognized from contracts with customers.

Notes to the Consolidated Financial Statements – APUC 2019 Annual Report | 114

Algonquin Power & Utilities Corp.
Notes to the Consolidated Financial Statements
December 31, 2019 and 2018
(in thousands of U.S. dollars, except as noted and per share amounts)

21. | Segmented information (continued)

| Year ended December 31, 2018
| Regulated Services Group |  | Renewable Energy Group |  | Corporate |  | Total
Revenue (1)(2) | $ | 1,401,240 |  |  | $ | 247,223 |  |  | $ | — |  |  | $ | 1,648,463 |
Fuel and power purchased | 456,974 |  |  | 27,164 |  |  | — |  |  | 484,138 |
Net revenue | 944,266 |  |  | 220,059 |  |  | — |  |  | 1,164,325 |
Operating expenses | 401,486 |  |  | 70,980 |  |  | — |  |  | 472,466 |
Administrative expenses | 33,234 |  |  | 18,539 |  |  | 937 |  |  | 52,710 |
Depreciation and amortization | 177,719 |  |  | 82,044 |  |  | 1,009 |  |  | 260,772 |
Gain on foreign exchange | — |  |  | — |  |  | (58 | ) |  | (58 | )
Operating income (loss) | 331,827 |  |  | 48,496 |  |  | (1,888 | ) |  | 378,435 |
Interest expense | (99,063 | ) |  | (50,920 | ) |  | (2,135 | ) |  | (152,118 | )
Income (loss) from long-term investments | 5,558 |  |  | 45,741 |  |  | (136,117 | ) |  | (84,818 | )
Other expenses | (6,775 | ) |  | (1,576 | ) |  | (687 | ) |  | (9,038 | )
Earnings (loss) before income taxes | $ | 231,547 |  |  | $ | 41,741 |  |  | $ | (140,827 | ) |  | $ | 132,461 |
Property, plant and equipment | $ | 4,210,115 |  |  | $ | 2,152,420 |  |  | $ | 31,023 |  |  | $ | 6,393,558 |
Investment carried at fair value | — |  |  | 814,530 |  |  | — |  |  | 814,530 |
Equity-method investees | 55 |  |  | 29,273 |  |  | 260 |  |  | 29,588 |
Total assets | 6,022,262 |  |  | 3,269,786 |  |  | 106,541 |  |  | 9,398,589 |
Capital expenditures | $ | 370,221 |  |  | $ | 96,148 |  |  | $ | — |  |  | $ | 466,369 |

(1) Revenue includes $14,953 related to net hedging gains from energy derivative contracts for the year ended December 31, 2018 that do not represent revenue recognized from contracts with customers.
(2) Regulated Services Group revenue includes $7,425 related to alternative revenue programs for the year ended December 31, 2018 that do not represent revenue recognized from contracts with customers.
The majority of non-regulated energy sales are earned from contracts with large public utilities. The Company has mitigated its credit risk to the extent possible by selling energy to large utilities in various North American locations. None of the utilities contribute more than 10% of total revenue.

Notes to the Consolidated Financial Statements – APUC 2019 Annual Report | 115

Algonquin Power & Utilities Corp.
Notes to the Consolidated Financial Statements
December 31, 2019 and 2018
(in thousands of U.S. dollars, except as noted and per share amounts)

21. | Segmented information (continued)

APUC operates in the independent power and utility industries in both Canada and the United States. Information on operations by geographic area is as follows:

| 2019 |  | 2018
Revenue |  |  |
Canada | $ | 87,226 |  |  | $ | 70,358 |
United States | 1,537,695 |  |  | 1,578,105 |
| $ | 1,624,921 |  |  | $ | 1,648,463 |
Property, plant and equipment |  |  |
Canada | $ | 752,016 |  |  | $ | 415,979 |
United States | 6,479,648 |  |  | 5,977,579 |
| $ | 7,231,664 |  |  | $ | 6,393,558 |
Intangible assets |  |  |
Canada | $ | 23,795 |  |  | $ | 23,994 |
United States | 23,821 |  |  | 31,000 |
| $ | 47,616 |  |  | $ | 54,994 |

Revenue is attributed to the two countries based on the location of the underlying generating and utility facilities.
22.Commitments and contingencies

(a) | Contingencies

APUC and its subsidiaries are involved in various claims and litigation arising out of the ordinary course and conduct of its business. Although such matters cannot be predicted with certainty, management does not consider APUC’s exposure to such litigation to be material to these consolidated financial statements. Accruals for any contingencies related to these items are recorded in the consolidated financial statements at the time it is concluded that its occurrence is probable and the related liability is estimable.
Claim by Gaia Power Inc.
On October 30, 2018, Gaia Power Inc. (“Gaia”) commenced an action in the Ontario Superior Court of Justice against APUC and certain of its subsidiaries, claiming damages of not less than $345,000 and punitive damages in the sum of $25,000. The action arises from Gaia’s 2010 sale, to a subsidiary of APUC, of Gaia’s interest in certain proposed wind farm projects in Canada. Pursuant to a 2010 royalty agreement, Gaia is entitled to royalty payments if the projects are developed and achieve certain agreed targets. It is too early to determine the likelihood of success in this lawsuit; however, APUC intends to vigorously defend it.
Condemnation expropriation proceedings
Liberty Utilities (Apple Valley Ranchos Water) Corp. is the subject of a condemnation lawsuit filed by the town of Apple Valley. A court will determine the necessity of the taking by Apple Valley and, if established, a jury will determine the fair market value of the assets being condemned. Resolution of the condemnation proceedings is expected to take two to three years. Any taking by government entities would legally require fair compensation to be paid; however, there is no assurance that the value received as a result of the condemnation will be sufficient to recover the Company’s net book value of the utility assets taken.

Notes to the Consolidated Financial Statements – APUC 2019 Annual Report | 116

Algonquin Power & Utilities Corp.
Notes to the Consolidated Financial Statements
December 31, 2019 and 2018
(in thousands of U.S. dollars, except as noted and per share amounts)

22.Commitments and contingencies (continued)

(b) | Commitments

In addition to the commitments related to the proposed acquisitions and development projects disclosed in notes 3 and 8, the following significant commitments exist as of December 31, 2019.
APUC has outstanding purchase commitments for power purchases, gas supply and service agreements, service agreements, capital project commitments and land easements.
Detailed below are estimates of future commitments under these arrangements:

| Year 1 | Year 2 | Year 3 | Year 4 | Year 5 | Thereafter | Total
Power purchase (i) | $ | 30,672 |  | $ | 11,422 |  | $ | 11,338 |  | $ | 11,566 |  | $ | 11,796 |  | $ | 179,412 |  | $ | 256,206 |
Gas supply and service agreements (ii) | 83,083 |  | 60,699 |  | 49,217 |  | 46,406 |  | 41,538 |  | 135,926 |  | 416,869 |
Service agreements | 47,950 |  | 40,456 |  | 41,554 |  | 45,611 |  | 47,005 |  | 293,436 |  | 516,012 |
Capital projects | 104,809 |  | 114,806 |  | — |  | — |  | — |  | — |  | 219,615 |
Land easements | 6,603 |  | 6,673 |  | 6,744 |  | 6,835 |  | 6,918 |  | 200,891 |  | 234,664 |
Total | $ | 273,117 |  | $ | 234,056 |  | $ | 108,853 |  | $ | 110,418 |  | $ | 107,257 |  | $ | 809,665 |  | $ | 1,643,366 |

(i) | Power purchase: APUC’s electric distribution facilities have commitments to purchase physical quantities of power for load serving requirements. The commitment amounts included in the table above are based on market prices as of December 31, 2019. However, the effects of purchased power unit cost adjustments are mitigated through a purchased power rate-adjustment mechanism.

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

23. | Non-cash operating items

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

| 2019 |  | 2018
Accounts receivable | $ | (20,857 | ) |  | $ | 3,005 |
Fuel and natural gas in storage | 13,985 |  |  | 1,351 |
Supplies and consumables inventory | (6,028 | ) |  | (7,189 | )
Income taxes recoverable | 17,796 |  |  | (763 | )
Prepaid expenses | (7,501 | ) |  | 2,907 |
Accounts payable | 63,854 |  |  | (22,915 | )
Accrued liabilities | 8,872 |  |  | 28,687 |
Current income tax liability | (5,016 | ) |  | 2,974 |
Asset retirements and environmental obligations | (2,494 | ) |  | (7,293 | )
Net regulatory assets and liabilities | (2,308 | ) |  | (8,890 | )
| $ | 60,303 |  |  | $ | (8,126 | )

Notes to the Consolidated Financial Statements – APUC 2019 Annual Report | 117

Algonquin Power & Utilities Corp.
Notes to the Consolidated Financial Statements
December 31, 2019 and 2018
(in thousands of U.S. dollars, except as noted and per share amounts)

24. | Financial instruments

(a) | Fair value of financial instruments

2019 | Carrying amount |  | Fair value |  | Level 1 |  | Level 2 |  | Level 3
Long-term investments carried at fair value | $ | 1,294,147 |  |  | $ | 1,294,147 |  |  | 1,178,581 |  |  | $ | 27,072 |  |  | $ | 88,494 |
Development loans and other receivables | 37,050 |  |  | 37,984 |  |  | — |  |  | 37,984 |  |  | — |
Derivative instruments: |  |  |  |  |  |  |  |  |
Energy contracts designated as a cash flow hedge | 65,304 |  |  | 65,304 |  |  | — |  |  | — |  |  | 65,304 |
Energy contracts not designated as a hedge | 20,384 |  |  | 20,384 |  |  | — |  |  | — |  |  | 20,384 |
Commodity contracts for regulated operations | 16 |  |  | 16 |  |  | — |  |  | 16 |  |  | — |
Total derivative instruments | 85,704 |  |  | 85,704 |  |  | — |  |  | 16 |  |  | 85,688 |
Total financial assets | $ | 1,416,901 |  |  | $ | 1,417,835 |  |  | $ | 1,178,581 |  |  | $ | 65,072 |  |  | $ | 174,182 |
Long-term debt | $ | 3,931,868 |  |  | $ | 4,284,068 |  |  | $ | 1,495,153 |  |  | $ | 2,788,915 |  |  | $ | — |
Convertible debentures | 342 |  |  | 623 |  |  | 623 |  |  | — |  |  | — |
Preferred shares, Series C | 13,793 |  |  | 15,120 |  |  | — |  |  | 15,120 |  |  | — |
Derivative instruments: |  |  |  |  |  |  |  |  |
Energy contracts designated as a cash flow hedge | 789 |  |  | 789 |  |  | — |  |  | — |  |  | 789 |
Energy contracts not designated as a hedge | 38 |  |  | 38 |  |  | — |  |  | — |  |  | 38 |
Cross-currency swap designated as a net investment hedge | 81,765 |  |  | 81,765 |  |  | — |  |  | 81,765 |  |  | — |
Commodity contracts for regulated operations | 2,072 |  |  | 2,072 |  |  | — |  |  | 2,072 |  |  | — |
Total derivative instruments | 84,664 |  |  | 84,664 |  |  | — |  |  | 83,837 |  |  | 827 |
Total financial liabilities | $ | 4,030,667 |  |  | $ | 4,384,475 |  |  | $ | 1,495,776 |  |  | $ | 2,887,872 |  |  | $ | 827 |

Notes to the Consolidated Financial Statements – APUC 2019 Annual Report | 118

Algonquin Power & Utilities Corp.
Notes to the Consolidated Financial Statements
December 31, 2019 and 2018
(in thousands of U.S. dollars, except as noted and per share amounts)

24. | Financial instruments (continued)

(a)Fair value of financial instruments (continued)

2018 | Carrying amount |  | Fair value |  | Level 1 |  | Level 2 |  | Level 3
Long-term investment carried at fair value | $ | 814,530 |  |  | $ | 814,530 |  |  | $ | 814,530 |  |  | $ | — |  |  | $ | — |
Development loans and other receivables | 103,696 |  |  | 110,019 |  |  | — |  |  | 110,019 |  |  | — |
Derivative instruments (1): |  |  |  |  |  |  |  |  |
Energy contracts designated as a cash flow hedge | 61,838 |  |  | 61,838 |  |  | — |  |  | — |  |  | 61,838 |
Currency forward contract not designated as a hedge | 869 |  |  | 869 |  |  | — |  |  | 869 |  |  | — |
Commodity contracts for regulatory operations | 101 |  |  | 101 |  |  | — |  |  | 101 |  |  | — |
Total derivative instruments | 62,808 |  |  | 62,808 |  |  | — |  |  | 970 |  |  | 61,838 |
Total financial assets | $ | 981,034 |  |  | $ | 987,357 |  |  | $ | 814,530 |  |  | $ | 110,989 |  |  | $ | 61,838 |
Long-term debt | $ | 3,336,795 |  |  | $ | 3,356,773 |  |  | $ | 768,400 |  |  | $ | 2,588,373 |  |  | $ | — |
Convertible debentures | 470 |  |  | 639 |  |  | 639 |  |  | — |  |  | — |
Preferred shares, Series C | 13,418 |  |  | 13,703 |  |  | — |  |  | 13,703 |  |  | — |
Derivative instruments: |  |  |  |  |  |  |  |  |
Energy contracts designated as a cash flow hedge | 57 |  |  | 57 |  |  | — |  |  | — |  |  | 57 |
Cross-currency swap designated as a net investment hedge | 93,198 |  |  | 93,198 |  |  | — |  |  | 93,198 |  |  | — |
Interest rate swaps designated as a hedge | 8,473 |  |  | 8,473 |  |  | — |  |  | 8,473 |  |  | — |
Commodity contracts for regulated operations | 1,114 |  |  | 1,114 |  |  | — |  |  | 1,114 |  |  | — |
Total derivative instruments | 102,842 |  |  | 102,842 |  |  | — |  |  | 102,785 |  |  | 57 |
Total financial liabilities | $ | 3,453,525 |  |  | $ | 3,473,957 |  |  | $ | 769,039 |  |  | $ | 2,704,861 |  |  | $ | 57 |

(1) Balance of $441 associated with certain weather derivatives have been excluded, as they are accounted for based on intrinsic value rather than fair value.
The Company has determined that the carrying value of its short-term financial assets and liabilities approximates fair value as of December 31, 2019 and 2018 due to the short-term maturity of these instruments.
The fair value of development loans and other receivables (level 2) is determined using a discounted cash flow method, using estimated current market rates for similar instruments adjusted for estimated credit risk as determined by management.
The fair value of the investment in Atlantica (level 1) is measured at the closing price on the NASDAQ stock exchange adjusted for the impact of the expected settlement under the purchase agreement pursuant to the prepayment of $53,750 (note 8(a)).

Notes to the Consolidated Financial Statements – APUC 2019 Annual Report | 119

Algonquin Power & Utilities Corp.
Notes to the Consolidated Financial Statements
December 31, 2019 and 2018
(in thousands of U.S. dollars, except as noted and per share amounts)

24. | Financial instruments (continued)

(a)Fair value of financial instruments (continued)
The Company’s level 1 fair value of long-term debt is measured at the closing price on the NYSE and the Canadian over-the-counter closing price. The Company’s level 2 fair value of long-term debt at fixed interest rates and Series C preferred shares has been determined using a discounted cash flow method and current interest rates. The Company’s level 2 fair value of convertible debentures has been determined as the greater of their face value and the quoted value of APUC’s common shares on a converted basis.
The Company’s level 2 fair value derivative instruments primarily consist of swaps, options, rights and forward physical derivatives where market data for pricing inputs are observable. Level 2 pricing inputs are obtained from various market indices and utilize discounting based on quoted interest rate curves which are observable in the marketplace.
The Company’s level 3 instruments consist of energy contracts for electricity sales and the fair value of the Company’s investment in AYES Canada. The significant unobservable inputs used in the fair value measurement of energy contracts are the internally developed forward market prices ranging from $13.33 to $178.65 with a weighted average of $23.66 as of December 31, 2019. The weighted average forward market prices are developed based on the quantity of energy expected to be sold monthly and the expected forward price during that month. The change in the fair value of the energy contracts is detailed in notes 24(b)(ii) and 24(b)(iv). The significant unobservable inputs used in the fair value measurement of the Company’s AYES Canada investment are the expected cash flows, the discount rates applied to these cash flows ranging from 8.75% to 9.50% with a weighted average of 9.42%, and the expected volatility of Atlantica’s share price ranging from 18% to 22% as of December 31, 2019. Significant increases (decreases) in expected cash flows or increases (decreases) in discount rate in isolation would have resulted in a significantly lower (higher) fair value measurement.

(b) | Derivative instruments

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

(i) | Commodity derivatives – regulated accounting

The Company uses derivative financial instruments to reduce the cash flow variability associated with the purchase price for a portion of future natural gas purchases associated with its regulated gas and electric service territories. The Company’s strategy is to minimize fluctuations in gas sale prices to regulated customers.
The following are commodity volumes, in dekatherms (“dths”) associated with the above derivative contracts:

| 2019 |
Financial contracts: Swaps | 2,134,739 |
Options | 150,000 |
Forward contracts | 2,500,000 |
| 4,784,739 |

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

Notes to the Consolidated Financial Statements – APUC 2019 Annual Report | 120

Algonquin Power & Utilities Corp.
Notes to the Consolidated Financial Statements
December 31, 2019 and 2018
(in thousands of U.S. dollars, except as noted and per share amounts)

24. | Financial instruments (continued)

(b) | Derivative instruments (continued)

(i) | Commodity derivatives – regulated accounting (continued)

The following table presents the impact of the change in the fair value of the Company’s natural gas derivative contracts had on the consolidated balance sheets:

|  | 2019 |  |  | 2018
Regulatory assets: |  |  |  |  |
Swap contracts |  | $ | 28 |  |  |  | $ | 66 |
Option contracts |  | 38 |  |  |  | — |
Forward contracts |  | $ | 1,830 |  |  |  | $ | — |
Regulatory liabilities: |  |  |  |  |
Swap contracts |  | $ | 743 |  |  |  | $ | 218 |
Option contracts |  | — |  |  |  | 134 |
Forward contracts |  | $ | — |  |  |  | $ | 1,259 |

(ii) | Cash flow hedges

The Company reduces the price risk on the expected future sale of power generation at Sandy Ridge, Senate and Minonk Wind Facilities by entering into the following long-term energy derivative contracts.

Notional quantity (MW-hrs) |  | Expiry |  | Receive average prices (per MW-hr) |  | Pay floating price (per MW-hr)
757,075 |  |  | December 2028 |  | 35.35 |  | PJM Western HUB
3,443,530 |  |  | December 2027 |  | 25.54 |  | PJM NI HUB
2,665,068 |  |  | December 2027 |  | 36.46 |  | ERCOT North HUB

In January 2019, the Company entered into a long-term energy derivative contract to reduce the price risk on the expected future sale of power generation at Sugar Creek. On September 30, 2019, the Company sold the derivative contract together with 100% of its ownership interest in Sugar Creek to AAGES Sugar Creek. The novation and transfer of the derivative contract was subject to counterparty approval, which was received subsequent to year-end in Q1 2020. As a result, the hedge relationship for the Sugar Creek energy derivative was discontinued. Amounts in AOCI of $15,765 and related tax were reclassified from AOCI into earnings in 2019 (note 24(b)(iv)).
During the year, the Company entered into an energy derivative contract to reduce the price risk on the expected future purchase of power on the open market at its Tinker Hydroelectric Facility with a notional quantity of 151,680 MW-hours and a price of $38.95 per MW-hr. The contract expires February 2022.
The Company was party to a 10-year forward-starting interest rate swap beginning on July 25, 2018 in order to reduce the interest rate risk related to the probable issuance on that date of a 10-year C$135,000 bond. During 2018, the Company amended and extended the forward-starting date of the interest rate swap to begin on March 29, 2019. During the year, the Company settled the forward-starting interest rate swap contract as it issued C$300,000 10-year senior unsecured notes with an interest rate of 4.60% (note 9(d)).
On May 23, 2019, the Company entered into a cross-currency swap, coterminous with the subordinated unsecured notes (note 9(e)), to effectively convert the $350,000 U.S. dollar denominated offering into Canadian dollars. The change in the carrying amount of the notes due to changes in spot exchange rates is recognized each period in the consolidated statements of operations as loss (gain) on foreign exchange. The Company designated the entire notional amount of the cross-currency fixed-for-fixed interest rate swap as a hedge of the foreign currency exposure related to cash flows for the interest and principal repayments on the notes. The gain or loss related to the fair value changes of the swap is first reported in OCI and a portion of the change is then reclassified from AOCI into earnings at each reporting date to offset the foreign exchange transaction gain or loss on the notes.

Notes to the Consolidated Financial Statements – APUC 2019 Annual Report | 121

Algonquin Power & Utilities Corp.
Notes to the Consolidated Financial Statements
December 31, 2019 and 2018
(in thousands of U.S. dollars, except as noted and per share amounts)

24. | Financial instruments (continued)

(b) | Derivative instruments (continued)

(ii) | Cash flow hedges (continued)

In September 2019, the Company entered into a forward-starting interest rate swap in order to reduce the interest rate risk related to the quarterly interest payments between July 1, 2024 and July 1, 2029 on the subordinated unsecured notes (note 9(e)). The Company designated the entire notional amount of the three pay-variable and receive-fixed interest rate swaps as a hedge of the future quarterly variable-rate interest payments associated with the subordinated unsecured notes.
The following table summarizes OCI attributable to derivative financial instruments designated as a cash flow hedge:

| 2019 |  | 2018
Effective portion of cash flow hedge | $ | 19,177 |  |  | $ | 1,567 |
Amortization of cash flow hedge | (33 | ) |  | (33 | )
Amounts reclassified from AOCI | (8,564 | ) |  | (4,224 | )
OCI attributable to shareholders of APUC | $ | 10,580 |  |  | $ | (2,690 | )

The Company expects $8,704 and $2,203 of unrealized gains currently in AOCI to be reclassified, net of taxes into non-regulated energy sales and interest expense, respectively, within the next twelve months, as the underlying hedged transactions settle.

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

The Company is exposed to currency fluctuations from its Canadian-based operations. APUC manages this risk primarily through the use of natural hedges by using Canadian long-term debt to finance its Canadian operations and a combination of foreign exchange forward contracts and spot purchases. APUC only enters into foreign exchange forward contracts with major North American financial institutions having a credit rating of A or better, thus reducing credit risk on these forward contracts.
The Company’s Canadian operations are determined to have the Canadian dollar as their functional currency and are exposed to currency fluctuations from their U.S. dollar transactions. The Company designates the amounts drawn on its revolving and bank credit facilities denominated in U.S. dollars as a hedge of the foreign currency exposure of its net investment in its U.S. investments and subsidiaries. The related foreign currency transaction gain or loss designated as, and effective as, a hedge of the net investment in a foreign operation are reported in the same manner as the translation adjustment (in OCI) related to the net investment. A foreign currency gain of $35,277 for the year ended December 31, 2019 (2018 - loss of $28,705) was recorded in OCI.
Concurrent with its C$150,000, C$200,000 and C$300,000 debenture offerings in December 2012, January 2014, and January 2017, respectively, the Company entered into cross currency swaps, coterminous with the debentures, to effectively convert the Canadian dollar denominated offering into U.S. dollars. The Company designated the entire notional amount of the cross-currency fixed-for-fixed interest rate swap and related short-term U.S. dollar payables created by the monthly accruals of the swap settlement as a hedge of the foreign currency exposure of its net investment in the Renewable Energy Group’s U.S. operations. The gain or loss related to the fair value changes of the swap and the related foreign currency gains and losses on the U.S. dollar accruals that are designated as, and are effective as, a hedge of the net investment in a foreign operation are reported in the same manner as the translation adjustment (in OCI) related to the net investment. A gain of $15,946 (2018 - loss of $41,244) was recorded in OCI in 2019.

Notes to the Consolidated Financial Statements – APUC 2019 Annual Report | 122

Algonquin Power & Utilities Corp.
Notes to the Consolidated Financial Statements
December 31, 2019 and 2018
(in thousands of U.S. dollars, except as noted and per share amounts)

24. | Financial instruments (continued)

(b) | Derivative instruments (continued)

(iv) | Other derivatives

The Company provides energy requirements to various customers under contracts at fixed rates. While the production from the Tinker Hydroelectric Facility is expected to provide a portion of the energy required to service these customers, APUC anticipates having to purchase a portion of its energy requirements at the ISO NE spot rates to supplement self-generated energy.
This risk is mitigated through the use of short-term financial forward energy purchase contracts that are classified as derivative instruments. The electricity derivative contracts are net settled fixed-for-floating swaps whereby APUC pays a fixed price and receives the floating or indexed price on a notional quantity of energy over the remainder of the contract term at an average rate, as per the following table. These contracts are not accounted for as hedges and changes in fair value are recorded in earnings as they occur.
The Company is exposed to interest rate fluctuations related to certain of its floating rate debt obligations, including certain project-specific debt and its revolving credit facilities, its interest rate swaps as well as interest earned on its cash on hand.
The Company is exposed to foreign exchange fluctuations related to the portion of its dividend declared and payable in U.S. dollars. This risk is mitigated through the use of currency forward contracts. For the year ended December 31, 2019, a foreign exchange loss of $983 (2018 - gain of $1,115) was recorded in the consolidated statements of operations. These currency forward contracts are not accounted for as a hedge.
For derivatives that are not designated as hedges, the changes in the fair value are immediately recognized in earnings.
The effects on the consolidated statements of operations of derivative financial instruments not designated as hedges consist of the following:

| 2019 |  | 2018
Change in unrealized loss (gain) on derivative financial instruments: |  |  |
Energy derivative contracts | $ | (530 | ) |  | $ | 77 |
Currency forward contract | 904 |  |  | (1,230 | )
Total change in unrealized loss (gain) on derivative financial instruments | $ | 374 |  |  | $ | (1,153 | )
Realized loss (gain) on derivative financial instruments: |  |  |
Energy derivative contracts | 227 |  |  | (73 | )
Currency forward contract | (147 | ) |  | 115 |
Total realized loss on derivative financial instruments | $ | 80 |  |  | $ | 42 |
Loss (gain) on derivative financial instruments not accounted for as hedges | 454 |  |  | (1,111 | )
Discontinued hedge accounting (note 24(b)(ii)) and other | (15,810 | ) |  | 632 |
| $ | (15,356 | ) |  | $ | (479 | )
Amounts recognized in the consolidated statements of operations consist of: |  |  |
Loss (gain) on derivative financial instruments | $ | (16,113 | ) |  | $ | 636 |
Loss (gain) on foreign exchange | 757 |  |  | (1,115 | )
| $ | (15,356 | ) |  | $ | (479 | )

Notes to the Consolidated Financial Statements – APUC 2019 Annual Report | 123

Algonquin Power & Utilities Corp.
Notes to the Consolidated Financial Statements
December 31, 2019 and 2018
(in thousands of U.S. dollars, except as noted and per share amounts)

24. | Financial instruments (continued)

(c) | Risk management

In the normal course of business, the Company is exposed to financial risks that potentially impact its operating results. The Company employs risk management strategies with a view of mitigating these risks to the extent possible on a cost effective basis. Derivative financial instruments are used to manage certain exposures to fluctuations in exchange rates, interest rates and commodity prices. The Company does not enter into derivative financial agreements for speculative purposes.
This note provides disclosures relating to the nature and extent of the Company’s exposure to risks arising from financial instruments, including credit risk and liquidity risk, and how the Company manages those risks.
Credit risk
Credit risk is the risk of an unexpected loss if a customer or counterparty to a financial instrument fails to meet its contractual obligations. The Company’s financial instruments that are exposed to concentrations of credit risk are primarily cash and cash equivalents, accounts receivable, notes receivable and derivative instruments. The Company limits its exposure to credit risk with respect to cash equivalents by ensuring available cash is deposited with its senior lenders, all of which have a credit rating of A or better. The Company does not consider the risk associated with the Renewable Energy Group accounts receivable to be significant as over 87% of revenue from power generation is earned from large utility customers having a credit rating of Baa2 or better by Moody’s, or BBB or higher by S&P, or BBB or higher by DBRS. Revenue is generally invoiced and collected within 45 days.
The remaining revenue is primarily earned by the Regulated Services Group, which consists of water and wastewater, electric and gas utilities in the United States and Canada. In this regard, the credit risk related to the Regulated Services Group accounts receivable balances of $200,594 is spread over thousands of customers. The Company has processes in place to monitor and evaluate this risk on an ongoing basis including background credit checks and security deposits from new customers. In addition, the regulators of the Regulated Services Group allow for a reasonable bad debt expense to be incorporated in the rates and therefore recovered from rate payers.
As of December 31, 2019, the Company’s maximum exposure to credit risk for these financial instruments was as follows:

| December 31, 2019
| Canadian $ |  | US $
Cash and cash equivalents and restricted cash | $ | 53,619 |  |  | $ | 45,989 |
Accounts receivable | 42,987 |  |  | 231,006 |
Allowance for doubtful accounts | (89 | ) |  | (4,850 | )
Notes receivable | 15,963 |  |  | 50,680 |
| $ | 112,480 |  |  | $ | 322,825 |

In addition, the Company continuously monitors the creditworthiness of the counterparties to its foreign exchange, interest rate, and energy derivative contracts prior to settlement, and assesses each counterparty’s ability to perform on the transactions set forth in the contracts. The counterparties consist primarily of financial institutions. This concentration of counterparties may impact the Company’s overall exposure to credit risk, either positively or negatively, in that the counterparties may be similarly affected by changes in economic, regulatory or other conditions.
Liquidity risk
Liquidity risk is the risk that the Company will not be able to meet its financial obligations as they fall due. The Company’s approach to managing liquidity risk is to ensure, to the extent possible, that it will always have sufficient liquidity to meet liabilities when due. As of December 31, 2019, in addition to cash on hand of $62,485, the Company had $1,047,216 available to be drawn on its senior debt facilities. Each of the Company’s revolving credit facilities contain covenants that may limit amounts available to be drawn.

Notes to the Consolidated Financial Statements – APUC 2019 Annual Report | 124

Algonquin Power & Utilities Corp.
Notes to the Consolidated Financial Statements
December 31, 2019 and 2018
(in thousands of U.S. dollars, except as noted and per share amounts)

24. | Financial instruments (continued)

(c) | Risk management (continued)

Liquidity risk (continued)
The Company’s liabilities mature as follows:

| Due less than 1 year |  | Due 2 to 3 years |  | Due 4 to 5 years |  | Due after 5 years |  | Total
Long-term debt obligations | $ | 602,028 |  |  | $ | 468,740 |  |  | $ | 600,721 |  |  | $ | 2,260,416 |  |  | $ | 3,931,905 |
Convertible debentures | — |  | — |  | — |  |  | — |  |  | 346 |  |  | 346 |
Advances in aid of construction | 1,165 |  |  | — |  |  | — |  |  | 59,663 |  |  | 60,828 |
Interest on long-term debt | 185,231 |  |  | 318,469 |  |  | 257,443 |  |  | 992,116 |  |  | 1,753,259 |
Purchase obligations | 458,288 |  |  | — |  |  | — |  |  | — |  |  | 458,288 |
Environmental obligation | 14,970 |  |  | 20,850 |  |  | 1,128 |  |  | 21,536 |  |  | 58,484 |
Derivative financial instruments: |  |  |  |  |  |  |  |  |
Cross-currency swap | 4,149 |  |  | 69,099 |  |  | 3,851 |  |  | 4,666 |  |  | 81,765 |
Energy derivative and commodity contracts | 1,631 |  |  | 909 |  |  | — |  |  | 359 |  |  | 2,899 |
Other obligations | 39,115 |  |  | 2,120 |  |  | 2,696 |  |  | 109,094 |  |  | 153,025 |
Total obligations | $ | 1,306,577 |  |  | $ | 880,187 |  |  | $ | 865,839 |  |  | $ | 3,448,196 |  |  | $ | 6,500,799 |

25. | Comparative figures

Certain of the comparative figures have been reclassified to conform to the financial statement presentation adopted in the current year.

Notes to the Consolidated Financial Statements – APUC 2019 Annual Report | 125

Notes 126 APUC 2019 Annual Report – Notes
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Notes – APUC 2019 Annual Report 127
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128 APUC 2019 Annual Report – Notes
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Corporate Information Directors Kenneth Moore Chair of the Board Managing Partner, NewPoint Capital Partners Inc. Chris Jarratt Vice Chair, Algonquin Power & Utilities Corp. Ian Robertson Chief Executive Officer, Algonquin Power & Utilities Corp. Christopher Ball Executive Vice President, Corpfinance International Ltd. D. Randy Laney Former Chairman of the Board The Empire District Electric Company Masheed Said Former Executive Vice President and Chief Operating Officer, U.S. Transmission, National Grid USA Dilek Samil Former Executive Vice President and Chief Operating Officer, NV Energy Melissa Stapleton Barnes Senior VP, Enterprise Risk Management Chief Ethics and Compliance Officer, Eli Lilly and Company George Steeves Principal, True North Energy Chris Huskilson Former President and CEO, Emera Inc. The Management Group Ian Robertson Chief Executive Officer Chris Jarratt Vice Chair David Bronicheski Chief Financial Officer Arun Banksota President Johnny Johnston Chief Operating Officer Jeff Norman Chief Development Officer Mary Ellen Paravalos Chief Compliance and Risk Officer Kirsten Olsen Chief Human Resources Officer Jennifer Tindale Chief Legal Officer George Trisic Chief Governance Officer and Corporate Secretary Head Office 354 Davis Road Oakville, Ontario L6J 2X1 Telephone: 905-465-4500 Fax: 905-465-4514 Website: www.AlgonquinPowerandUtilities.com Canadian Transfer Agent AST Trust Company (Canada) 1 Toronto Street, Suite 1200 Toronto, Ontario M5C 2V6 U.S. Transfer Agent AST American Stock Transfer & Trust Company, LLC 6201 15th Avenue Brooklyn, New York 11219 Auditors Ernst & Young, LLP Toronto, Ontario Stock Exchange The Toronto Stock Exchange: AQN, AQN.PR.A, AQN.PR.D The New York Stock Exchange: AQN, AQNA, AQNB APUC 2019 Annual Report 129
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Head Office: 354 Davis Road, Oakville, Ontario, Canada L6J 2X1 Tel: 905-465-4500 Fax: 905-465-4514 AQN_Utilities www.linkedin.com/company/algonquin-power-&-utilities-corp www.AlgonquinPowerandUtilities.com

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