EX-99.3 4 a2020q4-exhibit992xmda.htm EX-99.3 2020 Q4 MD&A
Management Discussion & Analysis
Management of Algonquin Power & Utilities Corp. (“AQN” 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, 2020. This Management Discussion & Analysis (“MD&A”) should be read in conjunction with AQN’s annual consolidated financial statements for the years ended December 31, 2020 and 2019. This material is available on SEDAR at www.sedar.com, on EDGAR at www.sec.gov/edgar, and on the AQN website at www.AlgonquinPowerandUtilities.com. Additional information about AQN, including the most recent Annual Information Form (“AIF”), can be found on SEDAR at www.sedar.com and on EDGAR at www.sec.gov/edgar.
Unless otherwise indicated, financial information provided for the years ended December 31, 2020 and 2019 has been prepared in accordance with generally accepted accounting principles in the United States (“U.S. GAAP”). As a result, the Company's financial information may not be comparable with financial information of other Canadian companies that provide financial information on another basis.
All monetary amounts are in U.S. dollars, except where otherwise noted. We denote any amounts denominated in Canadian dollars with "C$" immediately prior to the stated amount.
This MD&A is based on information available to management as of March 4, 2021.
Contents

Caution Concerning Forward-Looking Statements, Forward-Looking Information and non-GAAP Measures | 2
Overview and Business Strategy | 5
Significant Updates | 7
COVID-19 | 9
Outlook | 11
2020 Fourth Quarter Results From Operations | 12
2020 Annual Results From Operations | 14
2020 Adjusted EBITDA Summary | 17
Regulated Services Group | 18
Renewable Energy Group | 28
AQN: Corporate and Other Expenses | 33
Non-GAAP Financial Measures | 34
Corporate Development Activities | 37
Summary of Property, Plant and Equipment Expenditures | 38
Liquidity and Capital Reserves | 40
Share-Based Compensation Plans | 43
Management of Capital Structure | 44
Related Party Transactions | 44
Enterprise Risk Management | 45
Quarterly Financial Information | 60
Summary Financial Information of Atlantica | 61
Disclosure Controls and Internal Controls Over Financial Reporting | 61
Critical Accounting Estimates and Policies | 62

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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, earnings (including Adjusted Net Earnings per share) 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 impact of the 2019 novel coronavirus (“COVID-19”) on the Company’s business, operations, financial condition, cash flows and results of operations; expectations regarding the use of proceeds from financings; ongoing and planned acquisitions, projects and initiatives, including expectations regarding costs, financing, results, ownership structures, power purchase arrangements, regulatory matters, in-service dates and completion dates; the estimated impact of the Midwest Extreme Weather Event (as defined herein) on the Company, its operations, its facilities and its financial results, the Company's response to the Midwest Extreme Weather Event, the expected future recovery from customers of substantially all incremental commodity costs incurred with the Midwest Extreme Weather Event, and the expectation that the Company will have sufficient liquidity to fund such costs in the interim; the expected reduction in carbon emissions due to the retirement of the Asbury coal generation plant; expectations regarding the anticipated closing of AQN's acquisitions of New York American Water (as defined herein) and a 51% interest in the West Raymond Wind Facility; 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 the Company's development pipeline; expectations regarding regulatory hearings, motions, filings and approvals; expectations regarding the resumption of normal collection procedures; expectations regarding the cost of operations, capital spending and maintenance, and the variability of those costs; expected future generation of the Company’s energy facilities; expected future tax credits, including PTCs and ITCs (each as defined herein); expected future capital investments, including expected timing, investment plans, sources of funds and impacts; expectations regarding generation availability, capacity and production; expectations regarding the sale of renewable energy credits; 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 the impacts of a failed restructuring by the subsidiary of Abengoa that holds the interest in AAGES; expectations regarding the timing for completion of, and apportionment of liability for, the blade remediation work at the Sugar Creek and Maverick Creek Wind Facilities; expectations regarding expense reductions; contractual obligations and other commercial commitments; environmental liabilities; dividends to shareholders; expectations regarding the maturity and redemption of AQN's outstanding subordinated notes; expectations regarding the impact of tax reforms; credit ratings; anticipated growth and emerging opportunities in AQN’s target markets; the future impact on the Company of actual or proposed laws, regulations and rules; accounting estimates; interest rates; currency exchange rates; and commodity prices. All forward-looking information is given pursuant to the “safe harbor” provisions of applicable securities legislation.
The forecasts and projections that make up the forward-looking information contained herein are based on certain factors or assumptions which include, but are not limited to: the receipt of applicable regulatory approvals and requested rate decisions; the absence of material adverse regulatory decisions being received and the expectation of regulatory stability; the absence of any material equipment breakdown or failure; availability of financing (including tax equity financing and self-monetization transactions for U.S. federal tax credits) 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, financial or supply chain disruptions or liability due to natural disasters, diseases or other force majeure 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 closing of pending acquisitions substantially in accordance with the expected timing for such acquisitions; the absence of material capital project or financing cost overruns; sufficient liquidity and capital resources; the continuation of long term weather patterns and trends; the absence of significant counterparty defaults; the continued competitiveness of electricity pricing when compared with alternative sources of energy; the realization of the anticipated benefits of the Corporation’s acquisitions and joint ventures; the absence of a change in applicable laws, political conditions, public policies and directions by governments, materially negatively affecting the Corporation; the ability to obtain and maintain licenses and permits; maintenance of adequate insurance coverage; the absence of a material decrease in market energy prices; the absence of material disputes with taxation authorities or changes to applicable tax laws; continued maintenance

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of information technology infrastructure and the absence of a material breach of cybersecurity; favourable relations with external stakeholders; and favourable labour relations. Given the continued uncertainty and evolving circumstances surrounding the COVID-19 pandemic and related response from governments, regulatory authorities, businesses and customers, there is more uncertainty associated with the Corporation’s assumptions and expectations as compared to periods prior to the onset of COVID-19. For a discussion of the COVID-19 pandemic and its impact on the Company, see COVID-19.
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, diseases, pandemics and other force majeure events; critical equipment breakdown or failure; the failure of information technology infrastructure and cybersecurity; physical security breach; the loss of key personnel and/or labour disruptions; seasonal fluctuations and variability in weather conditions and natural resource availability; reductions in demand for electricity, gas and water due to developments in technology; reliance on transmission systems owned and operated by third parties; issues arising with respect to land use rights and access to the Corporation’s facilities; terrorist attacks; fluctuations in commodity 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; changes in laws and regulations; compliance with foreign laws or regulations; failure of compliance programs; 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 COVID-19; loss of key customers; failure to realize the anticipated benefits of acquisitions or joint ventures, including Atlantica (as defined herein) or the Corporation’s joint venture with Abengoa S.A ("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; fluctuations in the price and liquidity of the Corporation’s common shares and the Corporation's other securities; and the severity and duration of the COVID-19 pandemic and its collateral consequences, including the disruption of economic activity, volatility in capital and credit markets and legislative and regulatory responses. Although the Corporation has attempted to identify important factors that could cause actual actions, events or results to differ materially from those described in forward-looking information, there may be other factors that cause actions, events or results not to be as anticipated, estimated or intended. Some of these and other factors are discussed in more detail under the heading Enterprise Risk Management in this MD&A and under the heading Enterprise Risk Factors in the Corporation's most recent AIF.
Forward-looking information contained herein (including any financial outlook) is provided for the purposes of assisting the reader in understanding the Corporation and its business, operations, risks, financial performance, financial position and cash flows as at and for the periods indicated and to present information about management’s current expectations and plans relating to the future and the reader is cautioned that such information may not be appropriate for other purposes. Forward-looking information contained herein is made as of the date of this document and based on the plans, beliefs, estimates, projections, expectations, opinions and assumptions of management on the date hereof. There can be no assurance that forward-looking information will prove to be accurate, as actual results and future events could differ materially from those anticipated in such forward-looking information. Accordingly, readers should not place undue reliance on forward-looking information. While subsequent events and developments may cause the Corporation’s views to change, the Corporation disclaims any obligation to update any forward-looking information or to explain any material difference between subsequent actual events and such forward-looking information, except to the extent required by 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, AQN’s method of calculating these measures may differ from methods used by other companies and therefore may not be comparable to similar measures presented by other companies. A calculation and analysis of “Adjusted Net Earnings”, "Adjusted EBITDA", “Adjusted Funds from Operations”, "Net Energy Sales", "Net Utility Sales", and "Divisional Operating Profit", including a reconciliation to the U.S. GAAP equivalent, where applicable, 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. AQN uses these calculations to monitor the amount of cash generated by AQN. AQN uses Adjusted EBITDA to assess the operating performance of AQN without the effects of (as applicable): depreciation and amortization expense, income tax expense or recoveries, acquisition 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, costs related to management succession and executive retirement, costs related to prior period adjustments due to U.S. Tax Reform (as defined herein), costs related to condemnation proceedings, financial impacts on the Company's Senate Wind Facility (Texas) associated with the market disruption related to the Midwest Extreme Weather Event, 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 or unusual items. AQN adjusts for these factors as they may be non-cash, unusual in nature and are not factors used by management for evaluating the operating performance of the Company. AQN believes that presentation of this measure will enhance an investor’s understanding of AQN’s operating performance. Adjusted EBITDA is not intended to be representative of cash provided by operating activities or results of operations determined in accordance with U.S. GAAP, and can be impacted positively or negatively by these items.
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. AQN uses Adjusted Net Earnings to assess its performance without the effects of (as applicable): gains or losses on foreign exchange, foreign exchange forward contracts, interest rate swaps, acquisition 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), costs related to management succession and executive retirement, costs related to prior period adjustments due to U.S. Tax Reform, costs related to condemnation proceedings, financial impacts on the Company's Senate Wind Facility (Texas) associated with the market disruption related to the Midwest Extreme Weather Event, changes in value of investments carried at fair value, and other typically non-recurring or unusual items as these are not reflective of the performance of the underlying business of AQN. 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 AQN. AQN believes that analysis and presentation of net earnings or loss on this basis will enhance an investor’s understanding of the operating performance of its businesses. Adjusted Net Earnings is not intended to be representative of net earnings or loss determined in accordance with U.S. GAAP, and can be impacted positively or negatively by these items.
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. AQN 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 AQN. AQN believes that analysis and presentation of funds from operations on this basis will enhance an investor’s understanding of the operating performance of its businesses. Adjusted Funds from Operations is not intended to be representative of cash 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. AQN uses Net Energy Sales to assess its revenues without the effects of fluctuating commodity costs as such costs are predominantly passed through either directly or indirectly in the rates that are charged to customers. AQN believes that analysis and presentation of Net Energy Sales on this basis will enhance an investor’s understanding of the revenue generation of 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. AQN uses Net Utility Sales to assess its utility revenues without the effects of fluctuating commodity costs as such costs are predominantly passed through and paid for by utility customers. AQN believes that analysis and presentation of Net Utility Sales on this basis will enhance an investor’s understanding of the revenue generation of 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. AQN uses Divisional Operating Profit to assess the operating performance of its business groups without the effects of (as applicable): depreciation and amortization expense, corporate administrative expenses, income tax expense or recoveries, acquisition costs, 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. AQN adjusts for these factors as they may be non-cash, unusual in nature and are not factors used by management for evaluating the operating performance of the divisional units. Divisional Operating Profit is calculated inclusive of interest, dividend and equity income earned from indirect investments, and 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. AQN believes that presentation of this measure will enhance an investor’s understanding of AQN’s divisional operating performance. Divisional Operating Profit is not intended to be representative of cash provided by operating activities or results of operations determined in accordance with U.S. GAAP.
Capitalized terms used herein and not otherwise defined will have the meanings assigned to them in the Company's most recent AIF.
Overview and Business Strategy
AQN is incorporated under the Canada Business Corporations Act. AQN owns and operates a diversified portfolio of regulated and non-regulated generation, distribution, and transmission utility assets which are expected to deliver predictable earnings and cash flows. AQN 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. AQN strives to achieve these results while also seeking to maintain a business risk profile consistent with its BBB flat investment grade credit ratings and a strong focus on Environmental, Social and Governance factors.
AQN’s current quarterly dividend to shareholders is $0.1551 per common share or $0.6204 per common share per annum. Based on the Bank of Canada exchange rate on March 3, 2021, the quarterly dividend is equivalent to C$0.1959 per common share or C$0.7836 per common share per annum. AQN believes its annual dividend payout allows for both an immediate return on investment for shareholders and retention of sufficient cash within AQN to fund growth opportunities. Changes in the level of dividends paid by AQN are at the discretion of the AQN Board of Directors (the “Board”), with dividend levels being reviewed periodically by the Board in the context of AQN's financial performance and growth prospects.
AQN's operations are organized across two primary business units consisting of: the Regulated Services Group, which primarily owns and operates a portfolio of regulated assets in the United States, Canada, Chile and Bermuda and the Renewable Energy Group, which primarily owns and operates a diversified portfolio of renewable generation assets.
AQN 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 ratings 1. The business mix target may from time to time require AQN to grow its Regulated Services Group or implement other strategies in order to pursue investment opportunities within its Renewable Energy Group.
1 See Treasury Risk Management -Downgrade in the Company's Credit Rating Risk

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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 AQN. A more detailed description of AQN's organizational structure can be found in the most recent AIF.
Regulated Services Group
The Regulated Services Group operates a diversified portfolio of regulated utility systems throughout the United States, Canada, Chile and Bermuda serving approximately 1,086,000 customer connections (using an average of 2.5 customers per household, this translates into approximately 2,715,000 customers). The Regulated Services Group seeks to provide safe, high quality, and reliable services to its customers and to deliver stable and predictable earnings to AQN. In addition to encouraging and supporting organic growth within its service territories, the Regulated Services Group 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 U.S. States of California, New Hampshire, Missouri, Kansas, Oklahoma, and Arkansas, as well as in Bermuda, which together serve approximately 306,000 electric customer connections. The group also owns and operates generating assets with a gross capacity of approximately 1.6 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 U.S. States of Georgia, Illinois, Iowa, Massachusetts, New Hampshire, Missouri, and New York, and in the Canadian Province of New Brunswick, which together serve approximately 371,000 natural gas customer connections.
The Regulated Services Group's regulated water distribution and wastewater collection utility systems are located in the U.S. States of Arizona, Arkansas, California, Illinois, Missouri, and Texas as well as in Chile which together serve approximately 409,000 customer 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 directly owns and operates hydroelectric, wind, solar, and thermal facilities with a combined gross generating capacity of approximately 2.1 GW. Approximately 82% of the electrical output is sold pursuant to long term contractual arrangements which as of December 31, 2020 had a production-weighted average remaining contract life of approximately 13 years.

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In addition to directly owned and operated assets, the Renewable Energy Group has investments in generating assets with approximately 1.1 GW of net generating capacity which includes the Company's 44.2% interest in Atlantica Sustainable Infrastructure PLC ("Atlantica"). Atlantica owns and operates a portfolio of international clean energy and water infrastructure assets under long term contracts with a Cash Available for Distribution (CAFD) weighted average remaining contract life of approximately 17 years as of December 31, 2020.
Significant Updates
Operating Results
AQN 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 |  |
2020 |  | 2019 |  | Change |  | 2020 |  | 2019 |  | Change |  |  |  |  |  |
Net earnings attributable to shareholders | $504.2 |  | $172.1 |  | 193% |  | $782.5 |  | $530.9 |  | 47% |  |  |  |  |  |
Adjusted Net Earnings 1 | $127.0 |  | $103.6 |  | 23% |  | $365.8 |  | $321.3 |  | 14% |  |  |  |  |  |
Adjusted EBITDA 1 | $253.1 |  | $230.4 |  | 10% |  | $869.5 |  | $838.6 |  | 4% |  |  |  |  |  |
Net earnings per common share | $0.84 |  | $0.34 |  | 147% |  | $1.38 |  | $1.05 |  | 31% |  |  |  |  |  |
Adjusted Net Earnings per common share 1 | $0.21 |  | $0.20 |  | 5% |  | $0.64 |  | $0.63 |  | 2% |  |  |  |  |  |

1 | See Non-GAAP Financial Measures.

Declaration of 2021 First Quarter Dividend of $0.1551 (C$0.1959) per Common Share
AQN 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 AQN 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 March 4, 2021, AQN announced that the Board declared a first quarter 2021 dividend of $0.1551 per common share payable on April 15, 2021 to shareholders of record on March 31, 2021.
Based on the Bank of Canada exchange rate on March 3, 2021, the Canadian dollar equivalent for the first quarter 2021 dividend is C$0.1959 per common share.
The previous four quarter U.S and Canadian dollar equivalent dividends per common share have been as follows:

| Q2 2020 | Q3 2020 | Q4 2020 | Q1 2021 | Total
U.S. dollar dividend | $ | 0.1551 |  | $ | 0.1551 |  | $ | 0.1551 |  | $ | 0.1551 |  | $0.6204
Canadian dollar equivalent | $ | 0.2191 |  | $ | 0.2056 |  | $ | 0.2019 |  | $ | 0.1959 |  | $0.8225

AQN Surpasses the One Million Customer Connections Milestone
Acquisition of a Water and Wastewater Utility in Chile
On September 11, 2020, AQN entered into an agreement to acquire from Aguas Andinas S.A. its 53.5% direct and indirect participation in the water utility company Empresa de Servicios Sanitarios de Los Lagos S.A. ("ESSAL") for approximately $92.3 million. In compliance with local regulations, a tender offer process was launched for the remaining shares of ESSAL. The tender offer was completed on October 14, 2020 and the settlement of the tendered shares occurred on October 19, 2020, resulting in AQN acquiring, in total approximately 94% of the outstanding shares of ESSAL for an aggregate purchase price of approximately $162.1 million. Subsequently, on December 21, 2020, AQN entered into a share purchase agreement under which Toesca Infraestructura II Fondo de Inversión agreed to purchase an approximately 31.9% interest in Eco Acquisitionco SpA (the holding company through which AQN's interests in ESSAL are held) for a purchase price of approximately $51.8 million, which closed on January 4, 2021. As a result, AQN now indirectly owns approximately 64% of the outstanding shares of ESSAL.
ESSAL is a vertically integrated, regional water and wastewater provider with approximately 239,000 customer connections in Southern Chile. The acquisition is consistent with AQN's pillars of growth and sustainability and is expected to provide AQN with the opportunity to capitalize on its core competency of responsible utility ownership.
Acquisition of Ascendant
On November 9, 2020, AQN announced that it successfully completed its acquisition of Ascendant Group Limited ("Ascendant"). Ascendant's major subsidiary, Bermuda Electric Company ("BELCO"), is the sole electric utility in Bermuda,

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providing regulated electrical generation, transmission and distribution services to approximately 36,000 customer connections.
With the closing of the ESSAL and Ascendant acquisitions, the Regulated Services Group has expanded its footprint and now serves more than one million customer connections across the United States, Canada, Chile and Bermuda.
Completion of Renewable Construction Projects
Completion of Great Bay II Solar Project
On August 13, 2020, the Renewable Energy Group's 43 MW Great Bay II Solar Facility, located in southern Maryland, achieved full commercial operations (“COD”). The Great Bay II Solar Facility is the Renewable Energy Group’s fifth solar generating facility and is expected to generate approximately 72.9 GW-hrs of energy per year with the majority of output being sold through a long-term financial hedge.
Completion of the Sugar Creek Wind Project
On November 9, 2020, the Renewable Energy Group's 202 MW Sugar Creek Wind Facility, located in Logan County, Illinois, achieved COD. The Sugar Creek Wind Facility is the Renewable Energy Group's 13th wind powered electric generating facility and is expected to generate approximately 708.2 GW-hrs of energy per year with the majority of output being sold through a long-term financial hedge. Renewable Energy Credits ("REC") from the facility will be sold under long-term contracts to utilities in the State. In early 2021, the Renewable Energy Group exercised its option and purchased the remaining 50% interest in the project that it did not previously own.
Completion of the North Fork Ridge Wind Project
On December 31, 2020, the Regulated Service Group's approximately 150 MW North Fork Ridge Wind Facility in Missouri, part of the Mid-West Wind Development Project, achieved COD. Empire District Electric Company ("Empire") closed the acquisition of the North Fork Ridge Wind Facility on January 27, 2021 from an entity jointly owned by Liberty Utilities Co. ("LUCo") and one of the original developers.
Substantive Completion of the Maverick Creek Wind Project
On December 23, 2020, the Renewable Energy Group completed commissioning on 111 of the 127 total turbines at its 492 MW Maverick Creek Wind Facility, located in Concho County, Texas. Completion of the remaining 16 turbines is expected in March 2021. The Maverick Creek Wind Facility is the Renewable Energy Groups' 14th wind powered electric generating facility and upon full COD is expected to generate approximately 1,920 GW-hrs of energy per year with the majority of output being sold through two long-term power purchase agreements ("PPA"s) with investment grade rated entities. In early 2021, the Renewable Energy Group exercised its option and purchased the remaining 50% interest in the project that it did not previously own.
Acquisition of Majority Interest in Texas Coastal Wind Facilities
On November 20, 2020, the Renewable Energy Group entered into an agreement to acquire a 51% interest in a portfolio of four wind facilities (the "Texas Coastal Wind Facilities") from RWE Renewables Americas, LLC, a subsidiary of RWE AG. The Texas Coastal Wind Facilities, located in the coastal region of south Texas, are expected to have an aggregate capacity of 861 MW. Three wind facilities (Stella, Cranell and East Raymond), representing 621 MW of the total portfolio, have already achieved COD, with the fourth wind facility (West Raymond) expected to achieve COD in March 2021. The acquisitions of the three completed wind facilities have closed, with the acquisition of the West Raymond Wind Facility expected to close after achieving COD.
Sustainability Report and ESG Goals
On October 2, 2020, AQN released its 2020 Sustainability Report which outlines the Company’s progress towards its environmental, social and governance ("ESG") goals and demonstrates its ongoing commitment to delivering mission-critical services and renewable energy solutions. The 2020 Sustainability Report enhances the Company's ESG disclosure to provide transparency and a higher level of detail around priority ESG issues for the Company's stakeholders. Separately, in the fourth quarter of 2020, the Company released its first ever climate change assessment report in response to guidelines established by the Financial Stability Board's Task Force on Climate-Related Financial Disclosures.
Corporate Financings Completed
Common Equity Financing
On July 17, 2020, AQN closed the sale of approximately 57.5 million of its common shares at a price of C$17.10 per share (the "Offering"). The Offering was comprised of a widely marketed public offering through a syndicate of underwriters and concurrent direct offering to an institutional investor for aggregate gross proceeds of approximately $724 million (C$982.7 million).
During the twelve months ending December 31, 2020, AQN also issued approximately 8.7 million of its common shares under its at-the-market equity program ("ATM program") at an average price of $13.92 (C$18.96) for gross proceeds of approximately $120.6 million.

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The combined gross proceeds of both the Offering and of issuances pursuant to the ATM program in fiscal 2020 were approximately $845 million. Such proceeds were or will be used (as applicable) to partially finance AQN's previously announced renewable development growth projects and for general corporate purposes (see Equity).
Issuance of $600 Million of Green Senior Unsecured Notes
On September 23, 2020, the Regulated Services Group, through its financing affiliate Liberty Utilities Finance GP1, completed an inaugural offering into the U.S. 144A market with the issuance of $600.0 million of green senior unsecured notes bearing interest at 2.05% and having a maturity date of September 15, 2030 (the "Notes"). The net proceeds from the offering of the Notes were or will be, as applicable, used to finance or refinance wind energy projects and other eligible green investments (see Long Term Debt).
Issuance of C$200 million of senior unsecured debentures
On February 14, 2020, Liberty Utilities (Canada) LP, the holding company of the New Brunswick Gas System, established its Canadian Bond platform to finance the New Brunswick Gas System with the issuance of C$200.0 million of senior unsecured debentures bearing interest at 3.315% and a maturity date of February 14, 2050. The Canadian bond platform may be used for future debt issuances to accommodate future regulated utility growth in Canada. The debentures received a rating of BBB from DBRS (see Long Term Debt).
Midwest Extreme Weather Event
In February 2021, the Company’s operations were impacted by extreme winter storm conditions experienced in Texas and parts of the central U.S. (the "Midwest Extreme Weather Event").
Despite the extreme weather conditions, the Regulated Services Group’s mid-west electric and gas systems performed well through the extreme conditions delivering new system peaks. In line with other Southwest Power Pool utilities, limited and short lived load shedding was required to meet broader system requirements. The Company incurred incremental commodity costs during a period of record pricing and elevated consumption. The incremental commodity costs incurred by the Company are expected to be substantially recovered from customers over a timeframe to be agreed with its regulators. However, the Company expects it will have sufficient liquidity to fund these costs in the interim.
The Midwest Extreme Weather Event caused ice and freezing conditions, which restricted electricity production at certain of the Renewable Energy Group’s Texas-based wind facilities. The Company operates two facilities in Texas: the Senate Wind Facility in north-east Texas and the Maverick Creek Wind Facility in central Texas. The Company also has a 51% interest in the Stella, Cranell and East Raymond Texas Coastal Wind Facilities.
The most significantly impacted facility was the Senate Wind Facility, which has a financial hedge in place that imposes an obligation to deliver energy. Due to icing, the facility was unable to produce the required energy to satisfy the quantities required to be delivered under the hedge, and was required to settle in the market at elevated pricing. The impacts to the Company's other Texas wind facilities were marginal. The Maverick Creek Wind Facility has two unit contingent PPAs and as a result was not negatively subjected to the elevated market pricing. The Texas Coastal Wind Facilities experienced marginal impacts of the weather in aggregate.
The Company continues to assess the aggregate net impact of these unusual weather conditions on its business, operations, results and financial performance, with the ultimate impact being affected by a number of factors, including any government, regulatory or system operator action, and the outcomes of applicable disputes or proceedings. Based on available information, the unfavorable financial impact of the Midwest Extreme Weather Event on the Company's 2021 consolidated operating income is currently estimated to be between $45 million and $55 million, prior to potential mitigating factors.

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

COVID-19
As an operator of electric, water and gas utility systems and a generator of electricity, the Company provides essential services to communities in North America, Bermuda, and Chile. The Company has ensured that these utility services have continued uninterrupted since the onset of the public health measures taken to address the COVID-19 pandemic.
The Company holds the health, safety and well-being of its employees, customers and the communities in which it operates as a top priority. The Company is continuing to employ operational measures intended to protect the health and safety of its employees and customers and limit the risk of exposure to COVID-19. Some of the measures implemented include (i) restricted business travel, (ii) “work from home” policies where possible, (iii) physical distancing requirements between employees, customers, and the general public, (iv) restricted visitor interactions, including closure of local customer facing offices, (v) wide spread adoption of virtual meeting technology, (vi) precautions with respect to employee and facility hygiene, and (vii) supplying customer-facing and other front-line employees with personal protective equipment.
Currently, the Company is operating with approximately 65% of its employees working remotely. The Company continues to monitor the effects of COVID-19 closely and has formed a re-mobilization task force to develop a phased framework for returning employees back into the office environment only as and when it is safe to do so. The task force is assessing each work location for readiness and implementing additional safety protocols to support re-entry activities where necessary. The task force is also working with local agencies in an effort to secure the vaccine for 'essential worker' employees as well as tracking the general distribution of vaccinations to help inform the Company's remobilization activities.
Impact of COVID-19 on Operating Results
The COVID-19 pandemic and resulting business suspensions and shutdowns have changed consumption patterns of residential, commercial and industrial customers across all three modalities of utility services, including decreased consumption among certain commercial and industrial customers. Primarily as a result of the decreased demand, total Divisional Operating Profit of the Regulated Services Group for the three and twelve months ended December 31, 2020 decreased by approximately $0.7 million and $14.7 million as compared to the same periods in the prior year, and represents a reduction of approximately $0.02 on Adjusted Net Earnings per share 2 for the twelve months ended December 31, 2020 (see Non-GAAP Financial Measures). For the three and twelve months ended December 31, 2020, the Renewable Energy Group's results were not adversely impacted by the pandemic, due to a largely contracted and diversified generation fleet.
Accounts Receivable Collections and Bad Debt Expense
In response to COVID-19, and consistent with most utility companies in North America, the Company temporarily suspended disconnection activities for non-payment, waived late payment charges and suspended collection activities for overdue customer accounts across its utility service territories in the second quarter of 2020. As at December 31, 2020, these measures have resulted in collection delays which has increased accounts receivable greater than 60 days overdue to approximately 17% of total accounts receivable, compared to 7% as at December 31, 2019. The Company has resumed normal collection procedures in the majority of its jurisdictions and expects to expand normal collection procedures in other jurisdictions based on the guidance provided by the relevant regulatory authorities.
Cost containment strategies
In response to both the unfavourable weather variance experienced in the first quarter of 2020 and the impacts from COVID-19, the Company began implementing cost containment strategies that would not impact safe and reliable delivery of utility services to customers. For the twelve months ended December 31, 2020, the Company was able to achieve approximately $24.0 million in cost savings.
Regulated Mechanisms in Response to COVID-19
The Regulated Services Group is seeking recovery of incremental impacts related to COVID-19 in most of its regulatory jurisdictions. Of the Regulated Services Group's regulatory jurisdictions, 13 already have mechanisms in place or have approved accounting orders for the recording and tracking of such incremental impacts. In jurisdictions where such mechanisms are not already in place, the Regulated Services Group is in the process of seeking approval for such mechanisms, as needed.
Major Project Construction
In each of the jurisdictions where the Company's major renewable energy construction projects are located, construction of new renewable energy generation has been considered an essential activity exempt from government-mandated business shutdowns. As a result, construction activities have proceeded at all of the Company's major renewable energy construction projects throughout the COVID-19 pandemic.
2 The impacts of COVID-19 were estimated by normalizing sales in both periods for changes in weather and attributing the remaining variances to COVID-19.

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

In the second quarter of 2020, the U.S. Internal Revenue Service (the “IRS”) extended by one year the “continuity safe harbor” deadline by which wind and solar projects must be placed in service to qualify for the maximum permissible U.S. federal production tax credit (“PTC”) and investment tax credit (“ITC”), respectively. The Company expects that all of its U.S. wind and solar projects currently under construction will qualify for the maximum PTC and ITC, respectively.
Potential Future Impacts of COVID-19 on the Company in 2021
The Company’s business, financial condition, cash flows and results of operations are subject to actual and potential future impacts resulting from COVID-19, the full extent of which are not currently known. The extent of the future impact of the COVID-19 pandemic on the Company will depend on, among other things, the duration of the pandemic, the extent of the related public health response measures taken in response to the pandemic and the Company's efforts to mitigate the impact on its operations.
For a discussion of the risks the Company faces related to COVID-19 please refer to Enterprise Risk Management.
Outlook
The following discussion should be read in conjunction with the Forward-Looking Statements and Forward-Looking Information section in this MD&A.
Estimated 2021 Adjusted Net Earnings Per Share
The Company estimates that its Adjusted Net Earnings per share will be within a range of $0.71-$0.76 for the 2021 fiscal year (see Non-GAAP Financial Measures). This Adjusted Net Earnings per share estimate does not include the impacts on the Senate Wind Facility associated with the market disruption related to the Midwest Extreme Weather Event, which is estimated to negatively impact the Company's 2021 basic net earnings per share by approximately $0.06 before any potential recoveries. The Company views the financial impacts of the Midwest Extreme Weather Event on the Senate Wind Facility as unusual and not indicative of the on-going operating performance of such facility or the Company.
The Company's 2021 Adjusted Net Earnings per share estimate is based on the following key assumptions, as well as those set out under Forward-Looking Statements and Forward-Looking Information. For the bottom of the range, the Company has assumed: (i) a COVID-19 scenario similar to the COVID-19 impacts experienced by the Company in 2020, (ii) the closing of the Company’s acquisition of New York American Water in the fourth quarter of 2021, and (iii) a renewable energy resource estimate that is below long-term averages. For the top end of the range, the Company has assumed: (i) minimal impacts from COVID-19, (ii) the closing of the Company’s acquisition of New York American Water in the second quarter of 2021, and (iii) a renewable energy resource estimate that is consistent with long term averages. The Company has assumed normalized weather patterns for its estimated 2021 Adjusted Net Earnings per share range.
Capital Investment Expectations
The Company anticipates making capital investments of between $4.0 billion and $4.5 billion in 2021. See 2021 Capital Investments for a more detailed discussion of the Company's 2021 capital investment estimates.
The Company has also identified an approximately $9.4 billion development pipeline consisting of approximately 70% of investments in its Regulated Services Group and approximately 30% of investments in its Renewable Energy Group for the period from 2021 through the end of 2025 (see Corporate Development).

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

2020 Fourth Quarter Results From Operations

Key Financial Information | Three Months Ended December 31
(all dollar amounts in $ millions except per share information) | 2020 |  | 2019
Revenue | $ | 492.4 |  |  | $ | 440.0 |
Net earnings attributable to shareholders | 504.2 |  |  | 172.1 |
Cash provided by operating activities | 174.0 |  |  | 167.5 |
Adjusted Net Earnings 1 | 127.0 |  |  | 103.6 |
Adjusted EBITDA 1 | 253.1 |  |  | 230.4 |
Adjusted Funds from Operations 1 | 179.3 |  |  | 144.1 |
Dividends declared to common shareholders | 93.1 |  |  | 74.3 |
Weighted average number of common shares outstanding | 597,165,849 |  |  | 519,846,220 |
Per share |  |  |
Basic net earnings | $ | 0.84 |  |  | $ | 0.34 |
Diluted net earnings | $ | 0.83 |  |  | $ | 0.33 |
Adjusted Net Earnings 1,2 | $ | 0.21 |  |  | $ | 0.20 |
Dividends declared to common shareholders | $ | 0.16 |  |  | $ | 0.14 |

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

For the three months ended December 31, 2020, AQN experienced an average exchange rate of Canadian to U.S. dollars of approximately 0.7675 as compared to 0.7576 in the same period in 2019. As such, any quarter over quarter variance in revenue or expenses, in local currency, at any of AQN’s Canadian entities is affected by a change in the average exchange rate upon conversion to AQN’s reporting currency.
For the three months ended December 31, 2020, AQN reported total revenue of $492.4 million as compared to $440.0 million during the same period in 2019, an increase of $52.4 million or 11.9%. The major factors impacting AQN's revenue in the three months ended December 31, 2020 as compared to the same period in 2019 are set out as follows:

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

(all dollar amounts in $ millions) | Three Months Ended December 31
Comparative Prior Period Revenue | $ | 440.0 |
REGULATED SERVICES GROUP |
Existing Facilities |
Electricity: Increase is primarily due to higher pass through commodity costs at the CalPeco Electric System and in the Midwest compared to the same period in the prior year. The favourable variance was partially offset by fewer heating degree days at the Midwest. | 2.9 |
Gas: Decrease is primarily due to lower pass through commodity costs as compared to the same period in the prior year | (8.8) |
Water: Increase is primarily due to higher consumption and growth in connections at the Litchfield Park Water System, and higher pass through commodity costs at the Park Water System. | 3.3 |
Other: Decrease is primarily due to a reduction in projects at Ft. Benning. | (2.8) |
| (5.4) |
New Facilities |
Electricity: Acquisition of Ascendant (November 2020). | 29.1 |
Gas: Acquisition of St. Lawrence Gas (November 2019). | 2.0 |
Water: Acquisition of ESSAL (October 2020). | 19.9 |
| 51.0 |
Rate Reviews |
Electricity: Implementation of new rates effective January 2019 at the CalPeco Electric System and an increase in rates as a result of adding the Turquoise Solar Facility to its rate base as well as the implementation of new rates at the Granite State Electric System. | 2.9 |
Gas: Implementation of new rates at the EnergyNorth Gas System. | 2.2 |
Water: Decrease is primarily due to an unfavourable true up in interim rates with the 2019 general rate review at the Park Water System. | (1.4) |
| 3.7 |
Estimated Impact of COVID-19 1 | (0.7) |
RENEWABLE ENERGY GROUP |
Existing Facilities |
Hydro | 0.1 |
Wind Canada: Increase is primarily due to higher production. | 1.2 |
Wind U.S.: Increase is primarily due to higher overall production and favourable REC pricing, partially offset by unfavourable energy pricing. | 0.5 |
Solar: Increase is primarily due to favourable REC pricing at the Great Bay I Solar Facility. | 0.8 |
Thermal | — |
Other | (0.5) |
| 2.1 |
New Facilities |
Solar: Great Bay II Solar Facility achieved full COD in August 2020. | 1.4 |
| 1.4 |
Foreign Exchange | 0.3 |
Current Period Revenue | $ | 492.4 |

1 | The impacts of COVID-19 were estimated by normalizing sales in both periods for changes in weather and attributing the remaining variances to COVID-19.

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

A more detailed discussion of these factors is presented within the business unit analysis.
For the three months ended December 31, 2020, net earnings attributable to shareholders totaled $504.2 million as compared to $172.1 million during the same period in 2019, an increase of $332.3 million or 193.0%. The increase was due to a $14.1 million increase in earnings from operating facilities, a $365.9 million change in fair value of investments carried at fair value, a $1.9 million increase in interest, dividend, equity and other income, a $2.6 million decrease in pension and post-employment non-service costs, a $2.1 million decrease in interest expense, and a $2.8 million decrease in administrative expenses. These items were partially offset by a $2.5 million decrease in net effect of non-controlling interests, a $4.0 million increase in other net losses, a $1.3 million decrease in gains from derivative instruments, a $0.4 million increase in foreign exchange loss, a $10.3 million increase in depreciation and amortization expenses and a $38.6 million increase in income tax expense (tax explanations are discussed in AQN: Corporate and Other Expenses) as compared to the same period in 2019.
During the three months ended December 31, 2020, cash provided by operating activities totaled $174.0 million as compared to $167.5 million during the same period in 2019, an increase of $6.5 million. During the three months ended December 31, 2020, Adjusted Funds from Operations totaled $179.3 million as compared to Adjusted Funds from Operations of $144.1 million during the same period in 2019, an increase of $35.2 million (see Non-GAAP Financial Measures).
During the three months ended December 31, 2020, Adjusted EBITDA totaled $253.1 million as compared to $230.4 million during the same period in 2019, an increase of $22.7 million or 9.9%. 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).
2020 Annual Results From Operations

Key Financial Information | Twelve Months Ended December 31
(all dollar amounts in $ millions except per share information) | 2020 |  | 2019 |  | 2018 |  |
Revenue | $ | 1,677.1 |  |  | $ | 1,626.4 |  |  | $ | 1,648.5 |  |  |
Net earnings attributable to shareholders | 782.5 |  |  | 530.9 |  |  | 185.0 |  |  |
Cash provided by operating activities | 505.2 |  |  | 611.3 |  |  | 530.4 |  |  |
Adjusted Net Earnings 1 | 365.8 |  |  | 321.3 |  |  | 312.2 |  |  |
Adjusted EBITDA 1 | 869.5 |  |  | 838.6 |  |  | 804.4 |  |  |
Adjusted Funds from Operations 1 | 600.2 |  |  | 566.2 |  |  | 554.1 |  |  |
Dividends declared to common shareholders | 344.4 |  |  | 277.8 |  |  | 235.4 |  |  |
Weighted average number of common shares outstanding | 559,633,275 |  |  | 499,910,876 |  |  | 461,818,023 |  |  |
Per share |  |  |  |  |  |  |
Basic net earnings | $ | 1.38 |  |  | $ | 1.05 |  |  | $ | 0.38 |  |  |
Diluted net earnings | $ | 1.37 |  |  | $ | 1.04 |  |  | $ | 0.38 |  |  |
Adjusted Net Earnings 1,2 | $ | 0.64 |  |  | $ | 0.63 |  |  | $ | 0.66 |  |  |
Dividends declared to common shareholders | $ | 0.61 |  |  | $ | 0.55 |  |  | $ | 0.50 |  |  |
Total assets | 13,223.9 |  |  | 10,920.8 |  |  | 9,398.6 |  |  |
Long term debt 3 | 4,538.8 |  |  | 3,932.2 |  |  | 3,337.3 |  |  |

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

For the twelve months ended December 31, 2020, AQN experienced an average exchange rate of Canadian to U.S. dollars of approximately 0.7456 as compared to 0.7537 in the same period in 2019. As such, any year-over-year variance in revenue or expenses, in local currency, at any of AQN’s Canadian entities is affected by a change in the average exchange rate upon conversion to AQN’s reporting currency.
For the twelve months ended December 31, 2020, AQN reported total revenue of $1,677.1 million as compared to $1,626.4 million during the same period in 2019, an increase of $50.7 million or 3.1%. The major factors resulting in the increase in AQN revenue for the twelve months ended December 31, 2020 as compared to the same period in 2019 are set out as follows:

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

(all dollar amounts in $ millions) | Twelve Months Ended December 31
Comparative Prior Period Revenue | $ | 1,626.4 |
REGULATED SERVICES GROUP |
Existing Facilities |
Electricity: Decrease is primarily due to lower consumption driven by 4% fewer heating degree days and 15% fewer cooling degree days in the Midwest than the prior year. | (41.1) |
Gas: Decrease is primarily due to lower pass through commodity costs. | (40.8) |
Water: Increase is primarily due to higher consumption and growth in connections at the Litchfield Park Water System, and higher pass through commodity costs at the Park Water System. | 6.5 |
Other: Decrease is primarily due to a reduction in projects at Ft. Benning. | (2.5) |
| (77.9) |
New Facilities |
Electricity: Acquisition of Ascendant (November 2020). | 29.1 |
Gas: Acquisitions of New Brunswick Gas (October 2019) and St. Lawrence Gas (November 2019). | 61.2 |
Water: Acquisition of ESSAL (October 2020). | 19.9 |
| 110.2 |
Rate Reviews |
Electricity: Implementation of new rates effective January 2019 at the CalPeco Electric System and an increase in rates as a result of adding the Turquoise Solar Facility to its rate base as well as the implementation of new rates at the Granite State Electric System. | 18.6 |
Gas: Implementation of new rates at the EnergyNorth Gas System. | 2.2 |
Water: Decrease is primarily due to an unfavourable true up in interim rates with the 2019 general rate review at the Park Water System. | (0.7) |
| 20.1 |
Estimated Impact of COVID-19 1 | (15.7) |
RENEWABLE ENERGY GROUP |
Existing Facilities |
Hydro: Decrease is primarily due to unfavourable pricing at the Western and Maritime Regions, as well as lower overall production. | (0.3) |
Wind Canada: Increase is primarily due to higher production as well as the addition of the Amherst Island Wind Facility which was previously accounted for as an equity investment before the Company acquired the remaining 50% interest and began consolidating in April 2019. | 11.2 |
Wind U.S.: Increase is primarily due to favourable energy and REC pricing, as well as higher overall production. | 2.2 |
Solar: Increase is primarily due to favourable REC pricing at the Great Bay I Solar Facility. | 0.6 |
Thermal: Decrease is primarily due to unfavourable energy and capacity pricing as well as lower REC revenue at the Windsor Locks Thermal Facility. | (3.7) |
Other | 0.9 |
| 10.9 |
New Facilities |
Solar: Great Bay II Solar Facility achieved full COD in August 2020. | 4.0 |
| 4.0 |
Foreign Exchange | (0.9) |
Current Period Revenue | $ | 1,677.1 |

1 | The impacts of COVID-19 were estimated by normalizing sales in both periods for changes in weather and attributing the remaining variances to COVID-19.

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

A more detailed discussion of these factors is presented within the business unit analysis.
For the twelve months ended December 31, 2020, net earnings attributable to shareholders totaled $782.5 million as compared to $530.9 million during the same period in 2019, an increase of $251.6 million. The increase was due to a $44.5 million increase in earnings from operating facilities, a $281.6 million change in fair value of investments carried at fair value, a $5.2 million increase in foreign exchange gains, a $3.2 million decrease in pension and post-employment non-service costs, an $8.7 million increase in net effect of non-controlling interests, and a $5.5 million decrease in income tax expense (tax explanations are discussed in AQN: Corporate and Other Expenses). These items were partially offset by a $29.8 million increase in depreciation and amortization expenses, a $2.7 million increase in administration charges, a $14.5 million decrease in interest, dividend, equity and other income, a $34.6 million increase in other net losses, a $15.1 million decrease in gains from derivative instruments, and a $0.4 million increase in interest expense.
During the twelve months ended December 31, 2020, cash provided by operating activities totaled $505.2 million as compared to $611.3 million during the same period in 2019. During the twelve months ended December 31, 2020, Adjusted Funds from Operations totaled $600.2 million as compared to $566.2 million the same period in 2019, an increase of $34.0 million (see Non-GAAP Financial Measures).
During the twelve months ended December 31, 2020, Adjusted EBITDA totaled $869.5 million as compared to $838.6 million during the same period in 2019, an increase of $30.9 million or 3.7%. A detailed analysis of this variance is presented within the reconciliation of Adjusted EBITDA to net earnings set out below (see Non-GAAP Financial Measures).

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

2020 Adjusted EBITDA Summary
Adjusted EBITDA (see Non-GAAP Financial Measures) for the three months ended December 31, 2020 totaled $253.1 million as compared to $230.4 million during the same period in 2019, an increase of $22.7 million or 9.9%. Adjusted EBITDA for the twelve months ended December 31, 2020 totaled $869.5 million as compared to $838.6 million during the same period in 2019, an increase of $30.9 million or 3.7%. 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) | 2020 |  | 2019 |  | 2020 |  | 2019
Regulated Services Group Operating Profit | $ | 161.8 |  |  | $ | 159.4 |  |  | $ | 590.2 |  |  | $ | 566.4 |
Renewable Energy Group Operating Profit | 102.9 |  |  | 85.9 |  |  | 337.2 |  |  | 327.6 |
Administrative Expenses | (12.4) |  |  | (15.2) |  |  | (59.5) |  |  | (56.8) |
Other Income & Expenses | 0.8 |  |  | 0.3 |  |  | 1.6 |  |  | 1.4 |
Total AQN Adjusted EBITDA | $ | 253.1 |  |  | $ | 230.4 |  |  | $ | 869.5 |  |  | $ | 838.6 |
Change in Adjusted EBITDA ($) | $ | 22.7 |  |  |  |  | $ | 30.9 |  |  |
Change in Adjusted EBITDA (%) | 9.9 | % |  |  |  | 3.7 | % |  |

Change in Adjusted EBITDA | Three Months Ended December 31, 2020
(all dollar amounts in $ millions) | Regulated Services | Renewable Energy | Corporate | Total
Prior period balances | $ | 159.4 |  | $ | 85.9 |  | $ | (14.9) |  | $ | 230.4 |
Existing Facilities and Investments | (16.2) |  | 15.4 |  | 0.4 |  | (0.4) |
New Facilities and Investments | 15.6 |  | 1.3 |  | — |  | 16.9 |
Rate Reviews | 3.7 |  | — |  | — |  | 3.7 |
Estimated Impact of COVID-19 1 | (0.7) |  | — |  | — |  | (0.7) |
Foreign Exchange Impact | — |  | 0.3 |  | — |  | 0.3 |
Administrative Expenses | — |  | — |  | 2.9 |  | 2.9 |
Total change during the period | $ | 2.4 |  | $ | 17.0 |  | $ | 3.3 |  | $ | 22.7 |
Current period balances | $ | 161.8 |  | $ | 102.9 |  | $ | (11.6) |  | $ | 253.1 |

Change in Adjusted EBITDA | Twelve Months Ended December 31, 2020
(all dollar amounts in $ millions) | Regulated Services | Renewable Energy | Corporate | Total
Prior period balances | $ | 566.4 |  | $ | 327.6 |  | $ | (55.4) |  | $ | 838.6 |
Existing Facilities and Investments | (16.1) |  | 4.0 |  | 0.2 |  | (11.9) |
New Facilities and Investments | 34.5 |  | 3.8 |  | — |  | 38.3 |
Rate Reviews | 20.1 |  | — |  | — |  | 20.1 |
Estimated Impact of COVID-19 1 | (14.7) |  | — |  | — |  | (14.7) |
Foreign Exchange Impact | — |  | 1.8 |  | — |  | 1.8 |
Administrative Expenses | — |  | — |  | (2.7) |  | (2.7) |
Total change during the period | $ | 23.8 |  | $ | 9.6 |  | $ | (2.5) |  | $ | 30.9 |
Current period balances | $ | 590.2 |  | $ | 337.2 |  | $ | (57.9) |  | $ | 869.5 |

1 | The impacts of COVID-19 were estimated by normalizing sales in both periods for changes in weather and attributing the remaining variances to COVID-19.

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

REGULATED SERVICES GROUP
The Regulated Services Group operates rate-regulated utilities that as of December 31, 2020 provided distribution services to approximately 1,086,000 customer connections in the natural gas, electric, and water and wastewater sectors which is an increase of approximately 282,000 customer connections as compared to the prior year. The increase is due to the acquisitions in the second half of 2020 of (i) a majority interest in the ESSAL water utility in Chile (which added approximately 239,000 customer connections) and (ii) Ascendant in Bermuda (which added approximately 36,000 customer connections).
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 customer connections in the communities in which it operates.

Utility System Type | As at December 31
2020 | 2019
(all dollar amounts in $ millions) | Assets | Net Utility Sales 1 | Total Customer Connections 2 | Assets | Net Utility Sales 1 | Total Customer Connections 2
Electricity | 3,271.8 |  | 548.8 |  | 306,000 |  | 2,792.4 |  | 538.4 |  | 267,000 |
Natural Gas | 1,470.1 |  | 271.4 |  | 371,000 |  | 1,377.3 |  | 232.1 |  | 369,000 |
Water and Wastewater | 827.8 |  | 142.5 |  | 409,000 |  | 513.6 |  | 122.4 |  | 168,000 |
Other | 187.8 |  | 58.1 |  |  | 80.4 |  | 49.5 |  |
Total | $ | 5,757.5 |  | $ | 1,020.8 |  | 1,086,000 |  | $ | 4,763.7 |  | $ | 942.4 |  | 804,000 |
Accumulated Deferred Income Taxes Liability | $ | 520.1 |  |  |  | $ | 474.0 |  |  |

1 | Net Utility Sales for the twelve months ended December 31, 2019 and 2020. See Non-GAAP Financial Measures.
2 | Total Customer Connections represents the sum of all active and vacant customer connections.

The Regulated Services Group aggregates the performance of its utility operations by utility system type – electricity, natural gas, and water and wastewater systems.
The electric distribution systems are comprised of regulated electrical distribution utility systems and serve approximately 306,000 customer connections in the U.S. States of California, New Hampshire, Missouri, Kansas, Oklahoma and Arkansas and in Bermuda.
The natural gas distribution systems are comprised of regulated natural gas distribution utility systems and serve approximately 371,000 customer connections located in the U.S. States of New Hampshire, Illinois, Iowa, Missouri, Georgia, Massachusetts and New York and in the Canadian Province of New Brunswick.
The water and wastewater distribution systems are comprised of regulated water distribution and wastewater collection utility systems and serve approximately 409,000 customer connections located in the U.S. States of Arkansas, Arizona, California, Illinois, Missouri and Texas and in Chile.

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

Breakdown by Geographic Area
The Regulated Services Group's operations are located primarily in the United States. In 2019 the Regulated Services Group expanded its operations into Canada with the acquisition of the New Brunswick Gas System and in 2020 the Regulated Services Group expanded into Bermuda and Chile with the acquisitions of Ascendant and ESSAL. Below is a breakdown of Net Utility Sales by geographic area for the twelve months ended December 31, 2020 (see Non-GAAP Financial Measures).
2020 Annual Usage Results

Electric Distribution Systems | Three Months Ended December 31 |  | Twelve Months Ended December 31
| 2020 |  | 2019 |  | 2020 |  | 2019
Average Active Electric Customer Connections For The Period |  |  |  |  |  |  |
Residential | 263,200 |  |  | 228,000 |  |  | 262,100 |  |  | 227,200 |
Commercial and industrial | 42,300 |  |  | 38,100 |  |  | 42,200 |  |  | 38,100 |
Total Average Active Electric Customer Connections For The Period | 305,500 |  |  | 266,100 |  |  | 304,300 |  |  | 265,300 |
Customer Usage (GW-hrs) |  |  |  |  |  |  |
Residential | 638.0 |  |  | 599.7 |  |  | 2,485.9 |  |  | 2,488.1 |
Commercial and industrial | 896.3 |  |  | 932.1 |  |  | 3,406.0 |  |  | 3,944.5 |
Total Customer Usage (GW-hrs) | 1,534.3 |  |  | 1,531.8 |  |  | 5,891.9 |  |  | 6,432.6 |

For the three months ended December 31, 2020, the electric distribution systems' usage totaled 1,534.3 GW-hrs as compared to 1,531.8 GW-hrs for the same period in 2019, an increase of 2.5 GW-hrs or 0.2%. The increase in electricity consumption is primarily due to the acquisition of Ascendant but offset by load reduction due to COVID-19 related impacts to commercial and industrial customers at the Granite State and Empire Electric Systems compared to the same period in the previous year. The decrease in electricity consumption excluding the impact of the acquisition of Ascendant was 35.5 GW-hrs or 2.3%.
For the twelve months ended December 31, 2020, the electric distribution systems usage totaled 5,891.9 GW-hrs as compared to 6,432.6 GW-hrs for the same period in 2019, a decrease of 540.7 GW-hrs or 8.4%. The decrease in

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

electricity consumption is primarily due to load reduction due to COVID-19 related impacts and lower consumption driven by 4% fewer heating degree days and 15% fewer cooling degree days in the Midwest compared to the same period in the prior year.

Natural Gas Distribution Systems | Three Months Ended December 31 |  | Twelve Months Ended December 31
| 2020 |  | 2019 |  | 2020 |  | 2019
Average Active Natural Gas Customer Connections For The Period |  |  |  |  |  |  |
Residential | 316,700 |  |  | 302,700 |  |  | 317,100 |  |  | 303,100 |
Commercial and industrial | 37,300 |  |  | 35,700 |  |  | 37,700 |  |  | 35,600 |
Total Average Active Natural Gas Customer Connections For The Period | 354,000 |  |  | 338,400 |  |  | 354,800 |  |  | 338,700 |
Customer Usage (One Million British Thermal Units("MMBTU")) |  |  |  |  |  |  |
Residential | 6,022,000 |  |  | 6,341,000 |  |  | 21,214,000 |  |  | 20,213,000 |
Commercial and industrial | 6,159,000 |  |  | 5,969,000 |  |  | 22,032,000 |  |  | 15,676,000 |
Total Customer Usage (MMBTU) | 12,181,000 |  |  | 12,310,000 |  |  | 43,246,000 |  |  | 35,889,000 |

For the three months ended December 31, 2020, usage at the natural gas distribution systems totaled 12,181,000 MMBTU as compared to 12,310,000 MMBTU during the same period in 2019, a decrease of 129,000 MMBTU, or 1.0%. This was primarily as a result of COVID-19 related impacts at the New Brunswick Gas system, as well as volume reduction related to weather driven by 3% fewer heating degree days at the Midstates Gas System and 13% fewer heating degree days at the Empire Gas System as compared to the same period in the prior year.
For the twelve months ended December 31, 2020, usage at the natural gas distribution systems totaled 43,246,000 MMBTU as compared to 35,889,000 MMBTU during the same period in 2019, an increase of 7,357,000 MMBTU, or 20.5% primarily as a result of the acquisition of the New Brunswick Gas System and the St. Lawrence Gas System, which contributed approximately 12,000,000 MMBTU of usage.

Water and Wastewater Distribution Systems | Three Months Ended December 31 |  | Twelve Months Ended December 31
| 2020 |  | 2019 |  | 2020 |  | 2019
Average Active Customer Connections For The Period |  |  |  |  |  |  |
Wastewater customer connections | 45,900 |  |  | 44,400 |  |  | 45,300 |  |  | 43,900 |
Water distribution customer connections | 356,100 |  |  | 116,200 |  |  | 355,500 |  |  | 115,500 |
Total Average Active Customer Connections For The Period | 402,000 |  |  | 160,600 |  |  | 400,800 |  |  | 159,400 |
Gallons Provided (millions of gallons) |  |  |  |  |  |  |
Wastewater treated | 639 |  |  | 592 |  |  | 2,535 |  |  | 2,338 |
Water provided | 7,066 |  |  | 3,868 |  |  | 19,319 |  |  | 15,204 |
Total Gallons Provided (millions of gallons) | 7,705 |  |  | 4,460 |  |  | 21,854 |  |  | 17,542 |

For the three months ended December 31, 2020, the water and wastewater distribution systems provided approximately 7,066 million gallons of water to its customers and treated approximately 639 million gallons of wastewater. This is compared to 3,868 million gallons of water provided and 592 million gallons of wastewater treated during the same period in 2019, an increase in total gallons provided of 3,245 million, or 72.8%. The increase is primarily due to the acquisition of ESSAL in the fourth quarter of 2020, which contributed 2,677 million gallons of water provided.
For the twelve months ended December 31, 2020, the water and wastewater distribution systems provided approximately 19,319 million gallons of water to its customers and treated approximately 2,535 million gallons of wastewater. This is compared to 15,204 million gallons of water provided and 2,338 million gallons of water treated during the same period in 2019, an increase in total gallons provided of 4,312 million, or 24.6%. The increase is primarily due to the acquisition of ESSAL in the fourth quarter of 2020.

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

2020 Regulated Services Group Operating Results

| Three Months Ended December 31 |  | Twelve Months Ended December 31
(all dollar amounts in $ millions) | 2020 |  | 2019 |  | 2020 |  | 2019
Revenue |  |  |  |  |  |  |
Utility electricity sales and distribution | $ | 213.3 |  |  | $ | 181.9 |  |  | $ | 776.3 |  |  | $ | 785.8 |
Less: cost of sales – electricity | (69.4) |  |  | (59.2) |  |  | (227.5) |  |  | (247.4) |
Net Utility Sales - electricity 1 | 143.9 |  |  | 122.7 |  |  | 548.8 |  |  | 538.4 |
Utility natural gas sales and distribution | 124.9 |  |  | 131.3 |  |  | 415.7 |  |  | 402.6 |
Less: cost of sales – natural gas | (48.1) |  |  | (58.9) |  |  | (144.3) |  |  | (170.5) |
Net Utility Sales - natural gas 1 | 76.8 |  |  | 72.4 |  |  | 271.4 |  |  | 232.1 |
Utility water distribution & wastewater treatment sales and distribution | 52.9 |  |  | 32.0 |  |  | 155.0 |  |  | 130.5 |
Less: cost of sales – water | (3.2) |  |  | (2.2) |  |  | (12.5) |  |  | (8.1) |
Net Utility Sales - water distribution & wastewater treatment 1 | 49.7 |  |  | 29.8 |  |  | 142.5 |  |  | 122.4 |
Gas transportation | 12.1 |  |  | 11.4 |  |  | 39.1 |  |  | 35.1 |
Other revenue | 9.6 |  |  | 7.6 |  |  | 19.0 |  |  | 14.4 |
Net Utility Sales 1 | 292.1 |  |  | 243.9 |  |  | 1,020.8 |  |  | 942.4 |
Operating expenses | (133.8) |  |  | (96.0) |  |  | (445.5) |  |  | (397.1) |
Other income | 1.7 |  |  | 10.2 |  |  | 7.9 |  |  | 15.3 |
HLBV 2 | 1.8 |  |  | 1.3 |  |  | 7.0 |  |  | 5.8 |
Divisional Operating Profit 1,3 | $ | 161.8 |  |  | $ | 159.4 |  |  | $ | 590.2 |  |  | $ | 566.4 |

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 and Turquoise Solar Facilities.
3 | Certain prior year items have been reclassified to conform with current year presentation.

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

2020 Fourth Quarter Operating Results
For the three months ended December 31, 2020, the Regulated Services Group reported an operating profit (excluding corporate administration expenses) of $161.8 million as compared to $159.4 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 | $ | 159.4 |
Existing Facilities |
Electricity: Decrease is primarily due to lower consumption at the Empire Electric System driven by fewer heating degree days than the same period in the prior year. | (5.2) |
Gas: Decrease is primarily due to higher operating costs at the Midstates and EnergyNorth Gas Systems, partially offset by mechanism revenues at the New England Gas System. | (2.1) |
Water: Increase is primarily due to higher consumption and growth at the Litchfield Park Water System. | 1.0 |
Other: Decrease is due to lower earnings from the San Antonio Water System investment, lower income from allowance for funds used during construction (AFUDC), as well as reduction of projects at Ft. Benning. | (9.9) |
| (16.2) |
New Facilities |
Electricity: Acquisition of Ascendant (November 2020). | 8.6 |
Gas: Acquisition of St. Lawrence Gas (November 2019). | 1.1 |
Water: Acquisition of ESSAL (October 2020). | 5.9 |
| 15.6 |
Rate Reviews |
Electricity: Implementation of new rates effective January 2019 at the CalPeco Electric System and an increase in rates as a result of adding the Turquoise Solar Facility to its rate base as well as the implementation of new rates at the Granite State Electric System. | 2.9 |
Gas: Implementation of new rates at the EnergyNorth Gas System. | 2.2 |
Water: Decrease is due to an unfavourable true up in interim rates with the 2019 general rate review at the Park Water System. | (1.4) |
| 3.7 |
Estimated Impact of COVID-19 1 | (0.7) |
Current Period Divisional Operating Profit 2 | $ | 161.8 |

1 | The impacts of COVID-19 were estimated by normalizing sales in both periods for changes in weather and attributing the remaining variances to COVID-19.
2 | See Non-GAAP Financial Measures.

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

2020 Annual Operating Results
For the twelve months ended December 31, 2020, the Regulated Services Group reported an operating profit (excluding corporate administration expenses) of $590.2 million as compared to $566.4 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 | $ | 566.4 |
Existing Facilities |
Electricity: Decrease is primarily due to lower consumption at the Empire Electric System driven by fewer heating degree days and cooling degree days than the prior year as well as higher operating costs at the CalPeco Electric System. This was partially offset by operating cost savings at the Empire Electric System. | (8.5) |
Gas: Increase is primarily due to higher mechanism revenues at EnergyNorth and New England Gas Systems, partially offset by lower consumption driven by unfavourable weather at the Empire Gas System and higher operating costs at Midstates Gas System. | 1.2 |
Water: Increase is due to higher consumption and growth at the Litchfield Park Water System. | 0.2 |
Other: Decrease is due to fees earned from the San Antonio Water System investment, lower income from allowance for funds used during construction (AFUDC), as well as reduction of projects at Ft. Benning. | (9.0) |
| (16.1) |
New Facilities |
Electricity: Acquisition of Ascendant (November 2020). | 8.6 |
Gas: Acquisitions of New Brunswick Gas (October 2019) and St. Lawrence Gas (November 2019). | 20.0 |
Water: Acquisition of ESSAL (October 2020). | 5.9 |
| 34.5 |
Rate Reviews |
Electricity: Implementation of new rates at the CalPeco Electric System and an increase in rates as a result of adding the Turquoise Solar Facility to its rate base as well as the implementation of new rates at the Granite State Electric System. | 18.6 |
Gas: Implementation of new rates at the EnergyNorth Gas System. | 2.2 |
Water: Decrease is due to a true up in interim rates with the 2019 general rate review at the Park Water System. | (0.7) |
| 20.1 |
Estimated Impact of COVID-19 1 | (14.7) |
Current Period Divisional Operating Profit 2 | $ | 590.2 |

1 | The impacts of COVID-19 were estimated by normalizing sales in both periods for changes in weather and attributing the remaining variances to COVID-19.
2 | See Non-GAAP Financial Measures.

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

Regulatory Proceedings
The following table summarizes the major regulatory proceedings completed in 2020 and currently underway within the Regulated Services Group:

Utility | Jurisdiction | Regulatory Proceeding Type | Rate Request (millions) | Current Status
Completed Rate Reviews |  |  |  |
New England Gas System | Massachusetts | Gas System Enhancement Program ("GSEP") | $2.7 | On October 31, 2019, filed the 2020 GSEP application requesting an incremental increase in revenue of $2.7 million. On April 30, 2020, the application was approved for new rates effective May 1, 2020.
Energy North Gas System | New Hampshire | 2020 Cast Iron/Bare Steel Replacement Program Results | $1.6 | On April 15, 2020, filed its Annual 2020 Cast Iron/Bare Steel Replacement Program Results requesting recovery of an incremental revenue requirement for fiscal year 2020 of $1.6 million. On June 30, 2020, the New Hampshire Public Utilities Commission ("NHPUC") issued an order approving the requested revenue increase.
Granite State Electric System | New Hampshire | General Rate Case ("GRC") | $8.6 | On April 30, 2019, filed a rate review requesting increases of $5.7 million, subsequently updated to $6.7 million, effective May 1, 2020, (inclusive of a $2.1 million temporary increase effective July 1, 2019), plus a step increase of $2.1 million effective May 1, 2020, for certain capital additions as of December 31, 2019. On June 28, 2019, a temporary rate increase of $2.1 million was approved by the NHPUC. An order was issued June 30, 2020, approving recovery of a revenue requirement increase of $4.2 million beginning July 1, 2020. This is to be reconciled with temporary rates of $2.1 million that took effect on July 1, 2019. Multi-year step increases were approved of approximately $1.3 million, effective July 1, 2020; approximately $1.8 million effective July 1, 2021; and approximately $1.8 million effective July 1, 2022. Full revenue decoupling was approved effective July 1, 2021, with the continuation of a Lost Revenue Adjustment Mechanism during the period prior to the implementation of decoupling.

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

Utility | Jurisdiction | Regulatory Proceeding Type | Rate Request (millions) | Current Status
Empire Electric (Missouri System) | Missouri | GRC | $21.8 | On July 1, 2020, the Missouri Public Service Commission ("MPSC") issued an Order on the issues in the case resulting in an increase in revenue of approximately $1.0 million based on a 9.25% return on equity ("ROE") and on a 46% equity capital structure. In the Company's view, the proposed capital structure does not appropriately reflect the equity value at risk for the utility and is estimated to have a $5.7 million annual impact on the Company's returns. Also, neither the MPSC Staff's nor the Company's proposed weather normalization mechanism were approved, which allowed the Company the option to elect the use of Plant-In-Service Accounting (see further detail below). The Office of the Public Counsel ("OPC") and the Company filed applications for rehearing on July 10, 2020. On July 23, 2020, the MPSC issued an Amended Report and Order denying as moot both the Company and OPC's motions for rehearing. The Amended Report and Order provided clarification on the MPSC Staff's revenue requirement calculation. On July 31, 2020, second applications for rehearing were filed by OPC and the Company, which were denied on October 14, 2020. A Notice of Appeal to the Missouri Court of Appeals was filed by OPC on October 14, 2020, and on October 29, 2020, the Company filed its Notice of Appeal. The appeals were consolidated by the court, and briefs are being filed. The new rates, which were effective September 16, 2020, will remain in effect pending the appeals.
Peach State Gas System | Georgia | GRC | $2.9 | On April 1, 2020, filed an application for an annual increase in the revenue requirement of $2.9 million. On July 30, 2020, the Georgia Public Service Commission issued a final order approving the settlement agreement the Company reached with Staff for an increase of $1.6 million. The new rates were effective August 1, 2020.
CalPeco Electric System | California | GRC | $14.9 | On December 3, 2018, filed a three year application requesting a rate increase of $16.4 million ($6.7 million for 2019, $5.9 million for 2020 and $3.8 million for 2021). The requested rate increase was updated to $14.9 million over three years ($6.9 million for 2019, $4.1 million for 2020, and $3.9 million for 2021). In August 2020, the California Public Utilities Commission ("CPUC") issued an Order approving a $5.3 million revenue increase effective January 1, 2019 and an opportunity for an additional $3.1 million and $1.8 million in base rates for 2020 and 2021, respectively. The Post Test Year Adjustment Mechanism will be used for rate recovery of the 2020 and 2021 capital investments.
Various | Various | GRC | $1.1 | Approval of approximately $0.3 million in net rate decreases across two water utilities and one natural gas utility.

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

Utility | Jurisdiction | Regulatory Proceeding Type | Rate Request (millions) | Current Status
Pending Rate Reviews |  |  |  |
EnergyNorth Gas System | New Hampshire | GRC | $13.5 | On July 31, 2020, EnergyNorth filed an application requesting a permanent increase in annual revenue of approximately $13.5 million effective August 1, 2021, a request for a temporary increase in revenues of $6.5 million (effective October 1, 2020); and a step increase of $5.7 million annually associated with capital expenditure projects completed during the twelve months ending December 31, 2020 (effective no earlier than August 1, 2021). On September 30, 2020, the Commission issued an Order on temporary rates, setting temporary rates at the current level of distribution rates, approving an adjustment to the Revenue Per Customer (RPC) amounts upward to allow the Company to retain the December 31, 2019 test year level of revenue received (prior to decoupling adjustments), and approving an increase in distribution revenues to $92.9 million.
BELCO | Bermuda | GRC | $5.9 | On November 17, 2020, BELCO filed its revenue allowance application to request an allowance of approximately $204.0 million after adjustments and recommended a deferral of $16.6 million for recovery over three years commencing in 2022. On January 18, 2021, BELCO filed a revised revenue allowance application for approximately $213.0 million, removed the entire deferral recovery amount and requested an incremental increase of $5.9 million over 2020’s revenue allowance.
ESSAL | Chile | VII Tariff Process | N/A | ESSAL’s VII tariff process began in April 2020 to set rates for the five-year period from September 2021 to September 2026. A tariff decision is expected from the Superintendence of Sanitation Services (“SISS”) in the fourth quarter of 2021.
Various | Various | Various | $1.5 | Other pending rate review requests across one wastewater utility and one natural gas utility.

Retirement of Asbury Coal Facility
The Company retired its Asbury coal generation facility on March 1, 2020. This retirement did not have any financial impact on the Company's results for the twelve months ended December 31, 2020. The net book value of the facility has now been set up as a regulatory asset and will be subject to a future rate review proceeding. Retirement of the facility is expected to reduce CO2e emissions in excess of 905,000 metric tons annually.
Plant-In-Service Accounting
On August 12, 2020, under Revised Statutes of Missouri Section 393.1400, Empire elected to utilize Plant-In-Service Accounting which allows electrical corporations to defer eighty-five percent of all depreciation expense and return associated with all qualifying electric plants recorded to plant-in-service on the utility’s books, commencing from the date of election. Under this legislation, Empire expects the balance of the regulatory asset arising from these deferrals will be included in rate base in Empire’s next general rate proceeding. This election will allow deferrals until December 31, 2023, at which time the MPSC has discretion to allow new deferrals for an additional five years.
Impact on Regulatory Proceedings resulting from COVID-19
The Regulated Services Group is seeking recovery of incremental impacts related to COVID-19 in most of its regulatory jurisdictions. Of the Regulated Service Group's regulatory jurisdictions, 13 already have mechanisms in place or have approved accounting orders for the recording of and tracking of such incremental impacts. In jurisdictions where such mechanisms are not already in place, the Regulated Services Group is in the process of seeking approval for such mechanisms, as needed. The Regulated Services Group will seek recovery of the incremental impacts in future proceedings.

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

Regulatory Proceedings related to Acquisitions:
New York American Water
On November 20, 2019, LUCo entered a stock purchase agreement (the "SPA") with American Water Works Company Inc. ("American Water") to purchase all of the outstanding shares of New York American Water Company ("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 SPA has an initial termination date of June 30, 2021. Either party may extend the SPA beyond June 30, 2021. The ultimate termination date is December 31, 2021, if not bilaterally amended.
On February 28, 2020, the Company and American Water filed a joint petition with the New York State Public Service Commission ("NYSPSC") for approval of the acquisition. An evidentiary hearing on that joint petition has not yet been set by the Administrative Law Judge. A procedural conference has been scheduled for March 11, 2021 with a tentative hearing date set for May 17, 2021. The transaction is expected to close in 2021 and remains subject to regulatory approval and other closing conditions under the SPA.
On November 4, 2020, the Governor of the State of New York presented proposed legislation to the New York Legislature. This new legislation proposes to, among other things, amend the utility franchise revocation process for recurring failures to provide safe and adequate service and require the NYSPSC to undertake a study to determine whether a municipal takeover of the private water system in Nassau County would provide better service to residents of Nassau County. On February 3, 2021, the Governor of New York directed the Special Counsel for Ratepayer Protection at the NYSPSC to commence a municipalization feasibility study regarding a public takeover of New York American Water with the study to be completed by April 1, 2021 and with opportunities for public comment and public hearings. The Company will monitor that study and related processes and its impact on New York American Water and the Company, if any.
Tax Cuts and Jobs Act (“TCJA”)
Empire
On July 23, 2020, an Amended Report and Order was issued by the MPSC approving Empire's Excess Accumulated Deferred Income Tax (“Excess ADIT”) balance of $126.8 million. Three years of amortization period for unprotected Excess ADIT and Average Rate Assumption Method ("ARAM") for protected Excess ADIT was approved. For 2020, total amortization of $3.2 million of Excess ADIT was refunded to customers.
Furthermore, in the last GRC, the MPSC had directed Empire to establish a regulatory liability to address the impact of the TCJA on Empire’s rates from the date of the tax rate reduction to the effective date of lower base rates for Empire (January 1, 2018 to August 30, 2018), also known as the stub period. The MPSC ordered Empire to defer approximately $11.7 million of stub period tax savings benefits (stub period revenue) on its balance sheet as a regulatory liability. In this GRC, the MPSC ordered Empire to amortize the TCJA stub period revenue over five years for an annual amount of $2.3 million to be refunded to customers, effective September 16, 2020.
CalPeco Electric System
On September 2, 2020, an Order was issued approving $4.5 million in Excess ADIT with an amortization period of 42.4 years. A total of $0.2 million in Excess ADIT was refunded to customers in 2020.
Apple Valley and Park Water Systems
On October 2, 2020, an Order was issued deferring the Excess ADIT balance to be settled in the GRC. Preliminary estimated Excess ADIT balance of $3.4 million for the Park Water System and $4.6 million for the Apple Valley Water System were adopted in this GRC to be refunded to rate payers. Estimated Excess ADIT will be amortized using the straight line method and reconciled in the next GRC. A total of $0.5 million in Excess ADIT was refunded to customers in 2020.

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

RENEWABLE ENERGY GROUP

2020 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) |  | 2020 |  | 2019 |  |  | 2020 |  | 2019
Hydro Facilities: |  |  |  |  |  |  |  |  |  |  |
Maritime Region | 37.6 |  |  | 41.8 |  |  | 35.8 |  |  | 148.2 |  |  | 119.4 |  |  | 132.7 |
Quebec Region | 72.6 |  |  | 80.6 |  |  | 72.7 |  |  | 273.3 |  |  | 281.7 |  |  | 270.8 |
Ontario Region | 26.2 |  |  | 27.7 |  |  | 22.2 |  |  | 120.4 |  |  | 104.1 |  |  | 103.4 |
Western Region | 12.6 |  |  | 7.0 |  |  | 13.3 |  |  | 65.0 |  |  | 63.2 |  |  | 65.5 |
| 149.0 |  |  | 157.1 |  |  | 144.0 |  |  | 606.9 |  |  | 568.4 |  |  | 572.4 |
Canadian Wind Facilities: |  |  |  |  |  |  |  |  |  |  |
St. Damase | 22.7 |  |  | 21.9 |  |  | 20.5 |  |  | 76.9 |  |  | 76.9 |  |  | 76.7 |
St. Leon | 121.4 |  |  | 119.4 |  |  | 112.4 |  |  | 430.2 |  |  | 427.5 |  |  | 404.0 |
Red Lily 1 | 24.1 |  |  | 25.6 |  |  | 23.4 |  |  | 88.5 |  |  | 92.1 |  |  | 81.8 |
Morse | 30.5 |  |  | 31.6 |  |  | 25.9 |  |  | 108.8 |  |  | 111.2 |  |  | 96.4 |
Amherst | 67.9 |  |  | 70.6 |  |  | 67.0 |  |  | 229.8 |  |  | 216.3 |  |  | 223.4 |
| 266.6 |  |  | 269.1 |  |  | 249.2 |  |  | 934.2 |  |  | 924.0 |  |  | 882.3 |
U.S. Wind Facilities: |  |  |  |  |  |  |  |  |  |  |
Sandy Ridge | 43.6 |  |  | 41.1 |  |  | 31.9 |  |  | 158.3 |  |  | 143.8 |  |  | 126.5 |
Minonk | 189.8 |  |  | 195.1 |  |  | 193.7 |  |  | 673.7 |  |  | 618.5 |  |  | 654.6 |
Senate | 140.0 |  |  | 142.2 |  |  | 131.1 |  |  | 520.4 |  |  | 501.8 |  |  | 506.0 |
Shady Oaks | 100.5 |  |  | 102.9 |  |  | 97.7 |  |  | 355.6 |  |  | 319.6 |  |  | 345.8 |
Odell | 238.0 |  |  | 212.8 |  |  | 224.9 |  |  | 831.8 |  |  | 795.3 |  |  | 748.1 |
Deerfield | 167.9 |  |  | 174.2 |  |  | 163.9 |  |  | 546.0 |  |  | 541.0 |  |  | 522.6 |
Sugar Creek 4 | 123.9 |  |  | 62.8 |  |  | — |  |  | 123.9 |  |  | 62.8 |  |  | — |
Maverick Creek 5 | 295.2 |  |  | 137.8 |  |  | — |  |  | 295.2 |  |  | 137.8 |  |  | — |
| 1,298.9 |  |  | 1,068.9 |  |  | 843.2 |  |  | 3,504.9 |  |  | 3,120.6 |  |  | 2,903.6 |
Solar Facilities: |  |  |  |  |  |  |  |  |  |  |
Cornwall | 2.2 |  |  | 1.9 |  |  | 1.8 |  |  | 14.7 |  |  | 14.7 |  |  | 15.0 |
Bakersfield | 13.0 |  |  | 11.0 |  |  | 12.2 |  |  | 77.2 |  |  | 64.5 |  |  | 68.6 |
Great Bay 3 | 37.6 |  |  | 40.3 |  |  | 24.2 |  |  | 190.2 |  |  | 171.6 |  |  | 134.2 |
| 52.8 |  |  | 53.2 |  |  | 38.2 |  |  | 282.1 |  |  | 250.8 |  |  | 217.8 |
Renewable Energy Performance | 1,767.3 |  |  | 1,548.3 |  |  | 1,274.6 |  |  | 5,328.1 |  |  | 4,863.8 |  |  | 4,576.1 |
Thermal Facilities: |  |  |  |  |  |  |  |  |  |  |
Windsor Locks | N/A 2 |  | 34.0 |  |  | 28.0 |  |  | N/A 2 |  | 122.1 |  |  | 115.3 |
Sanger | N/A 2 |  | 25.5 |  |  | 17.8 |  |  | N/A 2 |  | 59.6 |  |  | 57.6 |
|  |  | 59.5 |  |  | 45.8 |  |  |  |  | 181.7 |  |  | 172.9 |
Total Performance |  |  | 1,607.8 |  |  | 1,320.4 |  |  |  |  | 5,045.5 |  |  | 4,749.0 |

1 | AQN owns a 75% equity interest but accounts for the facility using the equity method. The production figures represent full energy produced by the facility.
2 | Natural gas fired co-generation facility.
3 | The Great Bay II Solar Facility achieved partial completion on April 15, 2020 and COD on August 13, 2020.
4 | Achieved COD on November 9, 2020. The LTAR (as defined herein) noted above represents all production from the date of COD.
5 | Achieved partial completion on November 6, 2020. The LTAR noted above represents all production from the date of partial completion.

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

2020 Fourth Quarter Renewable Energy Group Performance
For the three months ended December 31, 2020, the Renewable Energy Group generated 1,607.8 GW-hrs of electricity as compared to 1,320.4 GW-hrs during the same period of 2019.
For the three months ended December 31, 2020, the hydro facilities generated 157.1 GW-hrs of electricity as compared to 144.0 GW-hrs produced in the same period in 2019, an increase of 9.1%. Electricity generated represented 105.4% of long-term average resources ("LTAR") as compared to 96.6% during the same period in 2019. During the quarter, all regions except the Western Region were above their respective LTAR.
For the three months ended December 31, 2020, the wind facilities produced 1,338.0 GW-hrs of electricity as compared to 1,092.4 GW-hrs produced in the same period in 2019, an increase of 22.5%. The increase in production is primarily due to the addition of the Sugar Creek Wind Facility which achieved COD on November 9, 2020, and the Maverick Creek Wind Facility which achieved partial completion on November 6, 2020. The wind facilities (excluding Sugar Creek and Maverick Creek) generated electricity equal to 99.2% of LTAR as compared to 95.3% during the same period in 2019.
For the three months ended December 31, 2020, the solar facilities generated 53.2 GW-hrs of electricity as compared to 38.2 GW-hrs of electricity in the same period in 2019, an increase of 39.3%. The increase in production is primarily due to the addition of the Great Bay II Solar Facility which achieved partial completion on April 15, 2020 and COD on August 13, 2020. The solar facilities (excluding Great Bay II) generated electricity equal to 93.9% of LTAR as compared to 93.4% in the same period in 2019.
For the three months ended December 31, 2020, the thermal facilities generated 59.5 GW-hrs of electricity as compared to 45.8 GW-hrs of electricity during the same period in 2019. During the same period, the Windsor Locks Thermal Facility generated 140.8 billion lbs of steam as compared to 153.7 billion lbs of steam during the same period in 2019.
2020 Annual Renewable Energy Group Performance
For the twelve months ended December 31, 2020, the Renewable Energy Group generated 5,045.5 GW-hrs of electricity as compared to 4,749.0 GW-hrs during the same period in 2019.
For the twelve months ended December 31, 2020, the hydro facilities generated 568.4 GW-hrs of electricity as compared to 572.4 GW-hrs produced in the same period in 2019, a decrease of 0.7%. Electricity generated represented 93.7% of LTAR as compared to 94.3% during the same period in 2019.
For the twelve months ended December 31, 2020, the wind facilities produced 4,044.6 GW-hrs of electricity as compared to 3,785.9 GW-hrs produced in the same period in 2019, an increase of 6.8%. The increase in production is primarily due to the addition of the Sugar Creek Wind Facility which achieved COD on November 9, 2020, and the Maverick Creek Wind Facility which achieved partial completion on November 6, 2020. The wind facilities (excluding Sugar Creek and Maverick Creek Wind Facility) generated electricity equal to 95.6% of LTAR as compared to 94.2% during the same period in 2019.
For the twelve months ended December 31, 2020, the solar facilities generated 250.8 GW-hrs of electricity as compared to 217.8 GW-hrs of electricity produced in the same period in 2019, an increase of 15.2%. The increase in production is primarily due to the addition of the Great Bay II Solar Facility which achieved partial completion on April 15, 2020 and COD on August 13, 2020. The solar facilities (excluding Great Bay II) generated electricity equal to 90.8% of LTAR as compared to 94.5% in the same period in 2019.
For the twelve months ended December 31, 2020, the thermal facilities generated 181.7 GW-hrs of electricity as compared to 172.9 GW-hrs of electricity during the same period in 2019. For the twelve months ended December 31, 2020, the Windsor Locks Thermal Facility generated 571.2 billion lbs of steam as compared to 555.4 billion lbs of steam during the same period in 2019.

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

2020 Renewable Energy Group Operating Results
| Three Months Ended December 31 |  | Twelve Months Ended December 31
(all dollar amounts in $ millions) | 2020 |  | 2019 |  | 2020 |  | 2019
Revenue 1 |  |  |  |  |  |  |
Hydro | $ | 10.8 |  |  | $ | 10.4 |  |  | $ | 39.8 |  |  | $ | 40.3 |
Wind | 51.0 |  |  | 49.4 |  |  | 166.0 |  |  | 153.3 |
Solar | 3.4 |  |  | 2.8 |  |  | 19.7 |  |  | 18.6 |
Thermal | 8.5 |  |  | 8.1 |  |  | 30.6 |  |  | 32.9 |
Total Revenue | $ | 73.7 |  |  | $ | 70.7 |  |  | $ | 256.1 |  |  | $ | 245.1 |
Less: |  |  |  |  |  |  |
Cost of Sales - Energy 2 | (1.4) |  |  | (0.9) |  |  | (5.1) |  |  | (4.3) |
Cost of Sales - Thermal | (3.5) |  |  | (3.2) |  |  | (11.5) |  |  | (13.0) |
Realized loss on hedges 3 | (0.2) |  |  | — |  |  | (1.1) |  |  | (0.2) |
Net Energy Sales 7 | $ | 68.6 |  |  | $ | 66.6 |  |  | $ | 238.4 |  |  | $ | 227.6 |
Renewable Energy Credits 4 | 4.1 |  |  | 2.8 |  |  | 12.4 |  |  | 10.1 |
Other Revenue | 0.1 |  |  | 0.8 |  |  | 1.9 |  |  | 1.4 |
Total Net Revenue | $ | 72.8 |  |  | $ | 70.2 |  |  | $ | 252.7 |  |  | $ | 239.1 |
Expenses & Other Income |  |  |  |  |  |  |
Operating expenses | (18.8) |  |  | (19.2) |  |  | (75.0) |  |  | (74.7) |
Dividend, interest, equity and other income 5 | 30.1 |  |  | 20.2 |  |  | 96.9 |  |  | 104.0 |
HLBV income 8 | 18.8 |  |  | 14.7 |  |  | 62.6 |  |  | 59.2 |
Divisional Operating Profit 6,7 | $ | 102.9 |  |  | $ | 85.9 |  |  | $ | 337.2 |  |  | $ | 327.6 |

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 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 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 PTCs
HLBV income represents the value of net tax attributes earned by the Renewable Energy Group in the period primarily from electricity generated by certain of its U.S. wind and U.S. solar generation facilities.
PTCs are earned as wind energy is generated based on a dollar per kW-hr rate prescribed in applicable federal and state statutes. For the three and twelve months ended December 31, 2020, the Renewable Energy Group's eligible facilities generated 765.4 and 2,600.4 GW-hrs representing approximately $19.1 million and $65.0 million in PTCs earned as compared to 745.5 and 2,557.8 GW-hrs representing $18.6 million and $63.9 million in PTCs earned during the same period in 2019. The majority of the PTCs have been allocated to tax equity investors to monetize the value to AQN of the PTCs and other tax attributes which are being recognized as HLBV income.

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

2020 Fourth Quarter Operating Results
For the three months ended December 31, 2020, the Renewable Energy Group's facilities generated $102.9 million of operating profit as compared to $85.9 million during the same period in 2019, which represents an increase of $17.0 million or 19.8%, 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 Divisional Operating Profit | $ | 85.9 |
Existing Facilities and Investments |
Hydro: Decrease is primarily due to lower production in the Western Region and unfavourable pricing in the Maritime Region. | (0.5) |
Wind Canada: Increase is primarily due to higher production. | 1.2 |
Wind U.S.: Increase is primarily due to higher production, partially offset by an increase in operating costs. | 4.0 |
Solar: Increase is primarily due to favourable REC pricing at the Great Bay I Solar Facility, partially offset by lower HLBV income. | 0.1 |
Thermal: Decrease is primarily due lower REC revenue at the Windsor Locks Thermal Facility as well as higher overall cost of fuel at the Sanger Thermal Facility. | (0.8) |
Investments: Decrease is primarily due to lower dividends related to AQN's investment in AYES Canada 1. | (0.9) |
Other: Increase is primarily from higher equity income and reimbursements from AAGES as well as higher capitalized development expenses. | 12.3 |
| 15.4 |
New Facilities and Investments |
Solar: Great Bay II Solar Facility achieved COD in August 2020. | 1.3 |
| 1.3 |
Foreign Exchange | 0.3 |
Current Period Divisional Operating Profit 2 | $ | 102.9 |

1 | See Note 8 and 16 in the annual consolidated financial statements.
2 | See Non-GAAP Financial Measures.

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

2020 Annual Operating Results
For the twelve months ended December 31, 2020, the Renewable Energy Group's facilities generated $337.2 million of operating profit as compared to $327.6 million during the same period in 2019, which represents an increase of $9.6 million or 2.9%, 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 Divisional Operating Profit | $ | 327.6 |
Existing Facilities |
Hydro: Decrease is primarily due to unfavourable pricing at the Western and Maritime Regions, as well as lower overall production. | (1.4) |
Wind Canada: Increase is primarily due to higher production, partially offset by an increase in operating costs. | 1.5 |
Wind U.S.: Increase is primarily due to overall favourable energy and REC pricing, higher overall production as well as higher HLBV income, partially offset by an increase in operating costs. | 7.8 |
Solar: Decrease is primarily due to lower overall HLBV income as all tax attributes at the Bakersfield I Solar Facility have been fully recognized. | (3.5) |
Thermal: Decrease is primarily due to unfavourable energy and capacity pricing as well as lower REC revenue at the Windsor Locks Thermal Facility, partially offset by overall lower cost of fuel. | (2.0) |
Investments: Decrease is primarily due to lower cash distributions and timing of a dividend received in the second quarter of 2019 related to AQN's investment in AYES Canada 1. | (3.3) |
Other: Increase is primarily from higher equity income and reimbursements from AAGES as well as higher capitalized development expenses. | 4.9 |
| 4.0 |
New Facilities and Investments |
Solar: Great Bay II Solar Facility achieved COD in August 2020. | 3.8 |
| 3.8 |
Foreign Exchange | 1.8 |
Current Period Divisional Operating Profit 2 | $ | 337.2 |

1 | See Note 8 and 16 in the annual consolidated financial statements.
2 | See Non-GAAP Financial Measures.

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

AQN: CORPORATE AND OTHER EXPENSES

| Three Months Ended December 31 |  | Twelve Months Ended December 31
(all dollar amounts in $ millions) | 2020 |  | 2019 |  | 2020 |  | 2019
Corporate and other expenses: |  |  |  |  |  |  |
Administrative expenses | $ | 12.4 |  |  | $ | 15.2 |  |  | $ | 59.5 |  |  | $ | 56.8 |
Loss (gain) on foreign exchange | 3.5 |  |  | 3.1 |  |  | (2.1) |  |  | 3.1 |
Interest expense | 45.3 |  |  | 47.4 |  |  | 181.9 |  |  | 181.5 |
Depreciation and amortization | 88.0 |  |  | 77.7 |  |  | 314.1 |  |  | 284.3 |
Change in value of investments carried at fair value | (464.0) |  |  | (98.1) |  |  | (559.7) |  |  | (278.1) |
Interest, dividend, equity, and other income 1 | (0.6) |  |  | (0.4) |  |  | (2.1) |  |  | (1.6) |
Pension and post-employment non-service costs | 4.7 |  |  | 7.3 |  |  | 14.1 |  |  | 17.3 |
Other net losses | 16.6 |  |  | 12.6 |  |  | 61.3 |  |  | 26.7 |
Loss (gain) on derivative financial instruments | 0.8 |  |  | (0.5) |  |  | (1.0) |  |  | (16.1) |
Income tax expense | 51.1 |  |  | 12.5 |  |  | 64.6 |  |  | 70.1 |

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

2020 Fourth Quarter Corporate and Other Expenses
For the three months ended December 31, 2020, administrative expenses totaled $12.4 million as compared to $15.2 million in the same period in 2019. The decrease was primarily due to lower travel costs and other administration expenses, partially offset by an increase in payroll and professional expenses.
For the three months ended December 31, 2020, interest expense totaled $45.3 million as compared to $47.4 million in the same period in 2019. The decrease was primarily due to lower reference rates on floating rate debt, partially offset by the acquisitions of Ascendant and ESSAL.
For the three months ended December 31, 2020, depreciation expense totaled $88.0 million as compared to $77.7 million in the same period in 2019. The increase was primarily due to higher overall property, plant and equipment, and the acquisitions of Ascendant and ESSAL.
For the three months ended December 31, 2020, change in investments carried at fair value totaled a gain of $464.0 million as compared to a gain of $98.1 million in 2019. 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 consolidated financial statements).
For the three months ended December 31, 2020, pension and post-employment non-service costs totaled $4.7 million as compared to $7.3 million in 2019. The decrease in 2020 was primarily due to lower expected return on assets in 2019 as well as lower cost of interest and higher amortization of actuarial losses in 2020.
For the three months ended December 31, 2020, other net losses were $16.6 million as compared to $12.6 million in the same period in 2019. The net losses in 2020 were primarily due to management succession and retirement expenses, condemnation costs for Liberty Utilities (Apple Valley Ranchos Water) Corp., and acquisition costs related to Ascendant and ESSAL (see Note 19 in the annual consolidated financial statements).
For the three months ended December 31, 2020, loss on derivative financial instruments totaled $0.8 million as compared to a gain of $0.5 million in the same period in 2019. The losses and gains in 2020 and 2019 were primarily related to mark-to-markets on energy derivatives.
For the three months ended December 31, 2020, an income tax expense of $51.1 million was recorded as compared to an income tax expense of $12.5 million during the same period in 2019. The increase in income tax expense was primarily due to the change in fair value associated with the investment in Atlantica, partially offset by tax credits earned. Tax credits can significantly affect the Company's effective income tax rate depending on the amount of pretax income. For the three months ended December 31, 2020, the Company accrued $15.0 million of ITCs and PTCs associated with renewable energy projects that have been placed in service by the end of 2020.

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

2020 Annual Corporate and Other Expenses
During the twelve months ended December 31, 2020, administrative expenses totaled $59.5 million as compared to $56.8 million in the same period in 2019. The increase primarily relates to increase in payroll, professional expenses, and additional costs incurred to administer AQN's operations as a result of the Company's growth.
For the twelve months ended December 31, 2020, interest expense totaled $181.9 million as compared to $181.5 million in the same period in 2019. The increase was primarily due to the issuance of subordinated unsecured notes in May of 2019, an increase in funds drawn on credit facilities and commercial paper issued and the acquisitions of Ascendant and ESSAL, partially offset by lower reference rates on floating rate debt.
For the twelve months ended December 31, 2020, depreciation expense totaled $314.1 million as compared to $284.3 million in the same period in 2019. The increase is primarily due to the timing of the Amherst Island Wind Facility consolidation as well as the acquisitions of the New Brunswick Gas, St. Lawrence Gas Systems, Ascendant and ESSAL.
For the twelve months ended December 31, 2020, change in investments carried at fair value totaled a gain of $559.7 million as compared to a gain of $278.1 million in the same period in 2019. 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 consolidated financial statements).
For the twelve months ended December 31, 2020, pension and post-employment non-service costs totaled $14.1 million as compared to $17.3 million in the same period in 2019. The decrease in 2020 is primarily due to a lower expected return on assets in 2019 as well as lower cost of interest and higher amortization of net actuarial losses in 2020.
For the twelve months ended December 31, 2020, other net losses were $61.3 million as compared to $26.7 million in the same period in 2019. The net losses in 2020 were primarily due to management succession and retirement expenses, adjustments related to U.S. Tax Reform, condemnation costs for Liberty Utilities (Apple Valley Ranchos Water) Corp., costs related to the Granite Bridge Project and acquisition costs related to Ascendant and ESSAL (see Note 19 in the annual consolidated financial statements).
For the twelve months ended December 31, 2020, the gain on derivative financial instruments totaled $1.0 million as compared to a gain of $16.1 million in the same period in 2019. The gains in 2020 were primarily related to the amortization of gains frozen in accumulated other comprehensive income as a result of hedge dedesignation when the Company's functional currency was changed. The gain in 2019 was primarily related to the discontinuation of hedge accounting on energy derivatives as a result of the Sugar Creek Wind Project sale to AAGES (see Note 24(b)(ii) in the annual consolidated financial statements).
An income tax expense of $64.6 million was recorded in the twelve months ended December 31, 2020, as compared to an income tax expense of $70.1 million during the same period in 2019. The decrease in income tax expense was primarily due to tax credits earned, tax benefits associated with higher corporate and other expenses partially offset by the change in fair value associated with the investment in Atlantica and a one-time income tax expense related to U.S. Tax Reform. Tax credits can significantly affect the Company's effective income tax rate depending on the amount of pretax income. For the twelve months ended December 31, 2020, the Company has earned $40.2 million of ITCs and PTCs associated with renewable energy projects that have been placed in service by the end of 2020. On April 8, 2020, the IRS issued final regulations with respect to rules regarding certain hybrid arrangements as a result of U.S. Tax Reform. As a result of the final regulations, the Company has recorded a one-time income tax expense of $9.3 million in the twelve months ended December 31, 2020, to reverse the benefit of deductions taken in the prior year (see Note 18 in the annual consolidated financial statements).

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

NON-GAAP FINANCIAL MEASURES
Reconciliation of Adjusted EBITDA to Net Earnings
The following table is derived from and should be read in conjunction with the consolidated statement of operations. This supplementary disclosure is intended to more fully explain disclosures related to Adjusted EBITDA and provides additional information related to the operating performance of AQN. 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) | 2020 |  | 2019 |  | 2020 |  | 2019
Net earnings attributable to shareholders | $ | 504.2 |  |  | $ | 172.1 |  |  | $ | 782.5 |  |  | $ | 530.9 |
Add (deduct): |  |  |  |  |  |  |
Net earnings attributable to the non-controlling interest, exclusive of HLBV 1 | 3.1 |  |  | (3.7) |  |  | 14.9 |  |  | 19.1 |
Income tax expense | 51.1 |  |  | 12.5 |  |  | 64.6 |  |  | 70.1 |
Interest expense | 45.3 |  |  | 47.4 |  |  | 181.9 |  |  | 181.5 |
Other net losses 3 | 16.6 |  |  | 12.6 |  |  | 61.3 |  |  | 26.7 |
Pension and post-employment non-service costs | 4.7 |  |  | 7.3 |  |  | 14.1 |  |  | 17.3 |
Change in value of investments carried at fair value 2 | (464.0) |  |  | (98.1) |  |  | (559.7) |  |  | (278.1) |
Loss (gain) on derivative financial instruments | 0.8 |  |  | (0.5) |  |  | (1.0) |  |  | (16.1) |
Realized loss on energy derivative contracts | (0.2) |  |  | — |  |  | (1.1) |  |  | (0.2) |
Loss (gain) on foreign exchange | 3.5 |  |  | 3.1 |  |  | (2.1) |  |  | 3.1 |
Depreciation and amortization | 88.0 |  |  | 77.7 |  |  | 314.1 |  |  | 284.3 |
Adjusted EBITDA | $ | 253.1 |  |  | $ | 230.4 |  |  | $ | 869.5 |  |  | $ | 838.6 |

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, 2020 amounted to $20.4 million and $69.5 million, respectively as compared to $16.0 million and $65.0 million, respectively, during the same period in 2019.
2 | See Note 8 in the annual consolidated financial statements.
3 | See Note 19 in the annual consolidated financial statements.

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

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

| Three Months Ended December 31 |  | Twelve Months Ended December 31
(all dollar amounts in $ millions except per share information) | 2020 |  | 2019 |  | 2020 |  | 2019
Net earnings attributable to shareholders | $ | 504.2 |  |  | $ | 172.1 |  |  | $ | 782.5 |  |  | $ | 530.9 |
Add (deduct): |  |  |  |  |  |  |
Loss (gain) on derivative financial instruments | 0.8 |  |  | (0.5) |  |  | (1.0) |  |  | (0.3) |
Realized loss on energy derivative contracts | (0.2) |  |  | — |  |  | (1.1) |  |  | (0.2) |
Other net losses 2 | 16.6 |  |  | 12.5 |  |  | 61.3 |  |  | 26.7 |
Loss (gain) on foreign exchange | 3.5 |  |  | 3.0 |  |  | (2.1) |  |  | 3.1 |
Change in value of investments carried at fair value 1 | (464.0) |  |  | (98.1) |  |  | (559.7) |  |  | (278.1) |
Other non-recurring adjustments | — |  |  | 2.2 |  |  | 1.0 |  |  | 2.2 |
Adjustment for taxes related to above 3 | 66.1 |  |  | 12.4 |  |  | 84.9 |  |  | 37.0 |
Adjusted Net Earnings | $ | 127.0 |  |  | $ | 103.6 |  |  | $ | 365.8 |  |  | $ | 321.3 |
Adjusted Net Earnings per share | $ | 0.21 |  |  | $ | 0.20 |  |  | $ | 0.64 |  |  | $ | 0.63 |

1 | See Note 8 in the annual consolidated financial statements.
2 | See Note 19 in the annual consolidated financial statements.
3 | Includes a one-time tax expense of $9.3 million to reverse the benefit of deductions taken in the prior year. See Note 18 in the annual consolidated financial statements.

For the three months ended December 31, 2020, Adjusted Net Earnings totaled $127.0 million as compared to Adjusted Net Earnings of $103.6 million for the same period in 2019, an increase of $23.4 million.
For the twelve months ended December 31, 2020, Adjusted Net Earnings totaled $365.8 million as compared to Adjusted Net Earnings of $321.3 million for the same period in 2019, an increase of $44.5 million.
The COVID-19 pandemic and resulting business suspensions and shutdowns have changed consumption patterns of residential, commercial and industrial customers across all three modalities of utility services, including decreased consumption among certain commercial and industrial customers. As a result of the decreased demand, Adjusted Net Earnings were negatively impacted for both the three and twelve months ended December 31, 2020, in the estimated amount of approximately $0.5 million and $10.9 million or approximately $0.02 annually on Adjusted Net Earnings per share 3.
Adjusted Net Earnings per share of $0.64 for the twelve months ended December 31, 2020 is slightly below the Company's previously disclosed expected range of $0.65 - $0.70 due to, among other things (i) the acquisition of Ascendant closing in November 2020 rather than September 2020 as previously assumed and (ii) unfavourable weather experienced for the three months ended December 31, 2020.
3 The impacts of COVID-19 were estimated by normalizing sales in both periods for changes in weather and attributing the remaining variances to COVID-19.

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

Reconciliation of Adjusted Funds from Operations to Cash Flows from Operating Activities
The following table is derived from and should be read in conjunction with the consolidated statement of operations and consolidated statement of cash flows. This supplementary disclosure is intended to more fully explain disclosures related to Adjusted Funds from Operations and provides additional information related to the operating performance of AQN. Investors are cautioned that this measure should not be construed as an alternative to cash flows from operating activities in accordance with U.S GAAP.
The following table shows the reconciliation of cash flows from operating activities to Adjusted Funds from Operations exclusive of these items:

| Three Months Ended December 31 |  | Twelve Months Ended December 31
(all dollar amounts in $ millions) | 2020 |  | 2019 |  | 2020 |  | 2019
Cash flows from operating activities | $ | 174.0 |  |  | $ | 167.5 |  |  | $ | 505.2 |  |  | $ | 611.3 |
Add (deduct): |  |  |  |  |  |  |
Changes in non-cash operating items | (2.8) |  |  | (29.8) |  |  | 77.5 |  |  | (60.3) |
Production based cash contributions from non-controlling interests | — |  |  | — |  |  | 3.4 |  |  | 3.6 |
Acquisition-related costs | 8.1 |  |  | 6.4 |  |  | 14.1 |  |  | 11.6 |
Adjusted Funds from Operations | $ | 179.3 |  |  | $ | 144.1 |  |  | $ | 600.2 |  |  | $ | 566.2 |

For the three months ended December 31, 2020, Adjusted Funds from Operations totaled $179.3 million as compared to Adjusted Funds from Operations of $144.1 million for the same period in 2019, an increase of $35.2 million.
For the twelve months ended December 31, 2020, Adjusted Funds from Operations totaled $600.2 million as compared to Adjusted Funds from Operations of $566.2 million for the same period in 2019, an increase of $34.0 million.
CORPORATE DEVELOPMENT ACTIVITIES
The Company undertakes development activities working with 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 a development pipeline of approximately $9.4 billion consisting of approximately $6.3 billion of investments in its Regulated Services Group and approximately $3.1 billion of investments in its Renewable Energy Group from 2021 through the end of 2025.
AQN 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 AQN to grow its Regulated Services Group or implement other strategies in order to pursue investment opportunities within its Renewable Energy Group.
See COVID-19 and Enterprise Risk Management in this MD&A for a description of certain of the impacts that COVID-19 has had, and may in the future have, on the Company’s development and construction projects.
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 was subsequently revised to consist of the development of an approximately 300 MW wind project in southeastern Kansas (Neosho Ridge), and two approximately 150 MW wind projects in southwestern Missouri (North Fork Ridge and Kings Point).
On May 9, 2019, the Arkansas Public Service Commission ("APSC") issued its order allowing the commencement of construction of the projects. In the fourth quarter of 2018, Empire applied to the MPSC for approval of certificates of CC&N for the projects. The MPSC issued an order approving the CC&N application, effective June 29, 2019. On December 30, 2020, the APSC issued an order approving Empire's acquisition of the three wind projects. On January 5, 2021, the Federal Energy Regulatory Commission ("FERC") approved Empire's acquisition of the North Fork Ridge Wind Project, on January 22, 2021 approved Empire's acquisition of the Neosho Ridge Wind Project, and on February 12, 2021 approved Empire's acquisition of the Kings Point Wind Project.

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On December 31, 2020, the 150 MW North Fork Ridge Wind Facility achieved COD. Empire closed the acquisition of the North Fork Ridge Wind Facility on January 27, 2021.
Empire is party to contracts to acquire the Neosho Ridge and Kings Point wind projects upon completion. Turbine installation is nearing completion, and project commissioning is underway, at these two sites.
SUMMARY OF PROPERTY, PLANT, AND EQUIPMENT EXPENDITURES

| Three Months Ended December 31 |  | Twelve Months Ended December 31
(all dollar amounts in $ millions) | 2020 |  | 2019 |  | 2020 |  | 2019
Regulated Services Group |  |  |  |  |  |  |
Rate Base Maintenance | $ | 54.7 |  |  | $ | 51.9 |  |  | $ | 210.8 |  |  | $ | 194.5 |
Rate Base Growth | 242.0 |  |  | 185.1 |  |  | 537.4 |  |  | 373.5 |
Property, Plant & Equipment Acquired 1 | 656.5 |  |  | 186.2 |  |  | 656.5 |  |  | 186.6 |
| $ | 953.2 |  |  | $ | 423.2 |  |  | $ | 1,404.7 |  |  | $ | 754.6 |
Renewable Energy Group |  |  |  |  |  |  |
Maintenance | $ | 11.4 |  |  | $ | 12.5 |  |  | $ | 27.5 |  |  | $ | 37.3 |
Investment in Capital Projects 2 | (126.4) |  |  | (47.1) |  |  | 103.3 |  |  | 425.8 |
International Investments | (11.9) |  |  | 28.0 |  |  | 10.3 |  |  | 122.2 |
| $ | (126.9) |  |  | $ | (6.6) |  |  | $ | 141.1 |  |  | $ | 585.3 |
Total Capital Expenditures | $ | 826.3 |  |  | $ | 416.6 |  |  | $ | 1,545.8 |  |  | $ | 1,339.9 |

1 | Property, Plant & Equipment acquired through acquisitions.
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.

2020 Fourth Quarter Property Plant and Equipment Expenditures
During the three months ended December 31, 2020, the Regulated Services Group invested $953.2 million ($296.7 million excluding acquisitions) in capital expenditures as compared to $423.2 million ($237.0 million excluding acquisitions) during the same period in 2019. 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, and initiatives relating to the safety and reliability of the electric and gas systems. Property, plant and equipment acquired of $656.5 million related to the acquisitions of Ascendant and ESSAL.
During the three months ended December 31, 2020, the Renewable Energy Group's incurred capital expenditures to fund the Maverick Creek, Sugar Creek, and Blue Hill Wind Projects, and the Altavista, Dimension and Carvers Creek Solar Projects, as well as ongoing maintenance capital at existing operating sites. During the three months ended December 31, 2020, the Blue Hill Wind and Altavista Solar joint ventures reimbursed the Company for funds previously advanced. As a result, the Renewable Energy Group recorded net capital reimbursements of $126.9 million as compared to $6.6 million during the same period in 2019.
2020 Annual Property Plant and Equipment Expenditures
During the twelve months ended December 31, 2020, the Regulated Services Group invested $1,404.7 million in capital expenditures as compared to $754.6 million during the same period in 2019. 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 additional investments in the Mid-West Wind Development Projects. Property, plant and equipment acquired of $656.5 million related to the acquisitions of Ascendant and ESSAL.
During the twelve months ended December 31, 2020, the Renewable Energy Group incurred capital expenditures of $141.1 million as compared to $585.3 million during the same period in 2019. The Renewable Energy Group's investment was primarily related to the development costs of the Altavista, Great Bay II, Dimension and Carvers Creek Solar Projects, the Maverick Creek, Sugar Creek, and Blue Hill Wind Projects, investments in an international solar project and ongoing sustaining capital at existing operating sites.

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

2021 Capital Investments
The following discussion should be read in conjunction with the Forward-Looking Statements and Forward-Looking Information section of this MD&A.
Over the course of the 2021 financial year, the Company expects to spend between $4.0 billion to $4.5 billion on capital investment opportunities. Actual expenditures in 2021 may vary due to, among other things, the impacts of COVID-19 and related response measures, the timing of various project investments and acquisitions, and the realized foreign exchange rates.
Ranges of expected capital investment in the 2021 financial year are as follows:

(all dollar amounts in $ millions) |  |  |
Regulated Services Group: |  |  |
Rate Base Maintenance | $ | 250.0 |  | - | $ | 300.0 |
Rate Base Growth | 1,750.0 |  | - | 1,825.0 |
Rate Base Acquisitions | 600.0 |  | - | 625.0 |
Total Regulated Services Group: | $ | 2,600.0 |  | - | $ | 2,750.0 |
Renewable Energy Group: |  |  |
Maintenance | $ | 25.0 |  | - | $ | 50.0 |
Investment in Capital Projects | 1,250.0 |  | - | 1,550.0 |
International Investments | 125.0 |  | - | 150.0 |
Total Renewable Energy Group: | $ | 1,400.0 |  | - | $ | 1,750.0 |
Total 2021 Capital Investments | $ | 4,000.0 |  | - | $ | 4,500.0 |

The Regulated Services Group expects to spend between $2,600.0 million to $2,750.0 million over the course of 2021 in an effort to expand 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 also expects to close the acquisitions of New York American Water and the Neosho Ridge and Kings Point Wind Projects in 2021.
The Renewable Energy Group intends to spend between $1,400.0 million to $1,750.0 million over the course of 2021 to develop or further invest in capital projects, primarily in relation to: (i) the acquisition of its joint venture partners' interest in the Maverick Creek and Sugar Creek Wind Projects and the Altavista Solar Project, and acquisition of the Texas Coastal Wind Facilities, (ii) development and construction (as applicable) of the Renewable Energy Group's wind and solar projects, and (iii) incremental international investments which includes an investment of approximately $132.7 million of additional ordinary shares of Atlantica purchased through a subscription agreement that was completed in early 2021 (see Note 8 (b) in the annual consolidated financial statements). Furthermore, the Renewable Energy Group plans to spend $25.0 million to $50.0 million on various operational solar, thermal, and wind assets to maintain safety, regulatory, and operational efficiencies.
The Company expects to fund its 2021 capital plan through a combination of retained cash, tax equity funding, senior notes, bank revolving and term credit facilities, and common equity or equity linked instruments.

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LIQUIDITY AND CAPITAL RESERVES
AQN has revolving credit and letter of credit facilities as well as separate credit facilities for the Regulated Services Group and the Renewable Energy Group to manage the liquidity and working capital requirements of each division (collectively the “Bank Credit Facilities”).
Bank Credit Facilities
The following table sets out the Bank Credit Facilities available to AQN and its operating groups as at December 31, 2020:

| As at December 31, 2020 |  | As at Dec 31, 2019
(all dollar amounts in $ millions) | Corporate |  | Regulated Services Group |  | Renewable Energy Group |  | Total |  | Total
Credit facilities | $ | 1,550.0 |  | 1 | $ | 1,175.0 |  |  | $ | 850.0 |  | 2 | $ | 3,575.0 |  |  | $ | 1,775.0 |
Funds drawn on facilities/ Commercial paper issued | (155.0) |  |  | (190.5) |  |  | — |  |  | (345.5) |  |  | (361.0) |
Letters of credit issued | (13.9) |  |  | (43.3) |  |  | (384.2) |  |  | (441.4) |  |  | (216.8) |
Liquidity available under the facilities | 1,381.1 |  |  | 941.2 |  |  | 465.8 |  |  | 2,788.1 |  |  | 1,197.2 |
Undrawn Portion of Uncommitted Letter of Credit Facilities | (39.8) |  |  | — |  |  | (66.0) |  |  | (105.8) |  |  | (149.9) |
Cash on hand |  |  |  |  |  |  | 101.6 |  |  | 62.5 |
Total Liquidity and Capital Reserves | $ | 1,341.3 |  |  | $ | 941.2 |  |  | $ | 399.8 |  |  | $ | 2,783.9 |  |  | $ | 1,109.8 |
1 Includes a $50 million uncommitted standalone letter of credit facility.
2 Includes a $350 million uncommitted standalone letter of credit facility.

Corporate
As at December 31, 2020, the Company's $500 million senior unsecured credit facility with a syndicate of banks (the "Corporate Credit Facility") had $155.0 million drawn and had $3.7 million of outstanding letters of credit. The Company has also issued $10.2 million of letters of credit from its $50 million uncommitted bi-lateral letter of credit facility. The Corporate Credit Facility matures on July 12, 2024.
Given the uncertainty around the length and extent of public health measures to address the COVID-19 pandemic and uncertainty around the extent of the impact on capital markets, the Company and its subsidiaries secured additional liquidity as an additional margin of safety intended to ensure the Company could continue to move forward with its capital expenditure program and committed acquisitions independent of the state of the capital markets. The additional liquidity was in the form of (i) a $865.0 million delayed draw non-revolving term credit facility with a syndicate of banks entered into on April 9, 2020 and maturing on April 8, 2021; and (ii) a $135.0 million bilateral delayed draw non-revolving term facility entered into on April 13, 2020 and maturing on April 12, 2021 (collectively, the "Corporate Delayed Draw Facilities"). On October 5, 2020, the two Corporate Delayed Draw Facilities were replaced with a syndicated $1.0 billion revolving credit facility (the "Corporate Liquidity Facility") maturing December 31, 2021. As at December 31, 2020, there were no amounts drawn on the Corporate Liquidity Facility. The Regulated Services Group also entered into a $600.0 million delayed draw non-revolving term credit facility with a syndicate of banks that matures on April 9, 2021 (the "Regulated Services Delayed Draw Facility"). On October 5, 2020, the Regulated Services Group also replaced the Regulated Services Delayed Draw Facility with a syndicated $600.0 million revolving credit facility (the "Regulated Services Liquidity Facility") maturing on December 31, 2021. As at December 31, 2020, there were no amounts drawn on the Regulated Services Liquidity Facility.
Regulated Services Group
As at December 31, 2020, the Regulated Services Group's $500.0 million senior unsecured syndicated revolving credit facility (the "Regulated Services Credit Facility") had no amounts drawn and had $43.3 million of outstanding letters of credit. The Regulated Services Credit Facility matures on February 23, 2023. As at December 31, 2020, $122.0 million of commercial paper was also issued and outstanding.
Through the acquisition of Ascendant on November 9, 2020, the Regulated Services Group acquired a $75.0 million senior unsecured revolving credit facility ("BELCO Credit Facility"). As at December 31, 2020, the BELCO Credit Facility had $68.5 million drawn. The BELCO Credit Facility matures on June 30, 2021.

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Renewable Energy Group
As at December 31, 2020, 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 $350.0 million letter of credit facility ("Renewable Energy LC Facility") maturing on June 30, 2021. As at December 31, 2020, the Renewable Energy Credit Facility had no amounts drawn and had $100.3 million in outstanding letters of credit. As at December 31, 2020, the Renewable Energy LC Facility had $284.0 million in outstanding letters of credit.
Long Term Debt
On February 15, 2020, the Company repaid, upon its maturity, a $6.5 million secured utility bond.
On April 30, 2020, the Company repaid, upon its maturity, a $100.0 million unsecured note.
On June 1, 2020, the Company repaid, upon its maturity, a $100.0 million secured utility bond.
On July 31, 2020, the Company repaid, upon its maturity, a $25.0 million unsecured note.
On December 22, 2020, the Company repaid, upon its maturity, a $25.0 million unsecured utility note.
On December 29, 2020, the Company repaid, upon its maturity, a $45.0 million unsecured utility note.
Issuance of Senior Notes
On February 14, 2020, Liberty Utilities (Canada) LP, the holding company of the New Brunswick Gas System, 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 AQN for the purchase of the New Brunswick Gas System which occurred on October 1, 2019.
On September 23, 2020, Liberty Utilities Finance GP1, the financing affiliate for LUCo, completed its inaugural offering into the U.S. 144A market with the issuance of $600.0 million of green senior unsecured notes bearing interest at 2.050% and having a maturity date of September 15, 2030. The Notes were priced at an issue price of 99.740% of their face value. The Notes will rank equally with all of LUCo's existing and future unsecured and unsubordinated indebtedness and senior in right of payment to all of LUCo's future subordinated indebtedness. The Notes were assigned ratings from Standard & Poor's ("S&P") and Fitch of BBB and BBB+ respectively. The net proceeds from the offering were or will be, as applicable, used to finance or refinance wind energy projects and other eligible green investments.
Credit Ratings
AQN 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.
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 Utilities Finance GP1, has a rating of BBB (high) from DBRS, BBB+ from Fitch and BBB from S&P. Empire has an issuer rating of BBB from S&P and a Baa1 rating from Moody's Investors Service, Inc.
Liberty Utilities (Canada) LP, the parent company for the Canadian regulated utilities under the Regulated Services Group, has an issuer rating of BBB from DBRS.
Algonquin Power Co. ("APCo"), 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.

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Contractual Obligations
Information concerning contractual obligations as of December 31, 2020 is shown below:

(all dollar amounts in $ millions) | Total |  | Due in less than 1 year |  | Due in 1 to 3 years |  | Due in 4 to 5 years |  | Due after 5 years
Principal repayments on debt obligations 1,2 | $ | 4,534.0 |  |  | $ | 334.4 |  |  | $ | 821.5 |  |  | $ | 285.6 |  |  | $ | 3,092.5 |
Advances in aid of construction | 79.8 |  |  | 1.2 |  |  | — |  |  | — |  |  | 78.6 |
Interest on long-term debt obligations 2 | 1,884.2 |  |  | 195.9 |  |  | 337.2 |  |  | 267.1 |  |  | 1,084.0 |
Purchase obligations | 561.7 |  |  | 561.7 |  |  | — |  |  | — |  |  | — |
Environmental obligations | 66.2 |  |  | 17.0 |  |  | 26.4 |  |  | 1.3 |  |  | 21.5 |
Derivative financial instruments: |  |  |  |  |  |  |  |  |
Cross currency interest rate swaps | 84.5 |  |  | 37.3 |  |  | 30.0 |  |  | 19.9 |  |  | (2.7) |
Interest rate swaps | 19.3 |  |  | 2.7 |  |  | 4.3 |  |  | 4.4 |  |  | 7.9 |
Energy derivative and commodity contracts | 6.5 |  |  | 1.9 |  |  | (0.2) |  |  | 0.9 |  |  | 3.9 |
Purchased power | 318.7 |  |  | 45.1 |  |  | 53.5 |  |  | 52.7 |  |  | 167.4 |
Gas delivery, service and supply agreements | 425.0 |  |  | 89.0 |  |  | 111.2 |  |  | 79.9 |  |  | 144.9 |
Service agreements | 496.7 |  |  | 56.8 |  |  | 97.0 |  |  | 94.4 |  |  | 248.5 |
Capital projects | 654.4 |  |  | 654.4 |  |  | — |  |  | — |  |  | — |
Land easements | 229.4 |  |  | 6.7 |  |  | 13.7 |  |  | 14.0 |  |  | 195.0 |
Other obligations | 216.2 |  |  | 79.2 |  |  | 6.6 |  |  | 5.2 |  |  | 125.2 |
Total Obligations | $ | 9,576.6 |  |  | $ | 2,083.3 |  |  | $ | 1,501.2 |  |  | $ | 825.4 |  |  | $ | 5,166.7 |

1 | Exclusive of deferred financing costs, bond premium/discount, fair value adjustments at the time of issuance or acquisition.
2 | The Company's subordinated unsecured notes have a maturity in 2078 and 2079, respectively. However, the Company currently anticipates repaying in 2023 and 2029 upon exercising its redemption right.

Equity
The common shares of AQN are publicly traded on the Toronto Stock Exchange ("TSX") and the New York Stock Exchange ("NYSE") under the trading symbol "AQN". As at March 3, 2021, AQN had 598,679,679 issued and outstanding common shares.
AQN may issue an unlimited number of common shares. The holders of common shares are entitled to dividends, if and when declared; to one vote for each share at meetings of the holders of common shares; and to receive a pro rata share of any remaining property and assets of AQN upon liquidation, dissolution or winding up of AQN. All shares are of the same class and with equal rights and privileges and are not subject to future calls or assessments.
AQN is also authorized to issue an unlimited number of preferred shares, issuable in one or more series, containing terms and conditions as approved by the Board. As at December 31, 2020, AQN 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 July 17, 2020, AQN closed the sale of approximately 57.5 million of its common shares at a price of C$17.10 per share to a syndicate of underwriters and an institutional investor for gross proceeds of approximately C$982.7 million. Approximately 37.0 million common shares, which included the exercise of an over-allotment option of approximately 4.8 million common shares, were sold to a syndicate of underwriters for gross proceeds of approximately C$633 million. Approximately 20.5 million common shares were sold to an institutional investor for gross process of approximately C$350.0 million. The net proceeds were or will be used (as applicable) to partially finance AQN's previously announced renewable development growth projects and for general corporate purposes.

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At-The-Market Equity Program
On May 15, 2020, AQN re-established its ATM program that allows the Company to issue up to $500 million of common shares from treasury to the public from time to time, at the Company's discretion, at the prevailing market price when issued on the TSX, the NYSE, or any other existing trading market for the common shares of the Company in Canada or the United States. During the twelve months ended December 31, 2020, the Company issued 8,664,563 common shares under the ATM program at an average price of $13.92 per common share for gross proceeds of $120.6 million ($119.1 million net of commissions). Other related costs, primarily related to the re-establishment of the ATM program, were $1.3 million.
As at March 4, 2021, the Company has issued a cumulative total of 10,421,362 common shares under its ATM program at an average price of $13.69 per share for gross proceeds of approximately $142.7 million ($140.8 million net of commissions). Other related costs, primarily related to the establishment and subsequent re-establishment of the ATM program, were $3.4 million.
Dividend Reinvestment Plan
AQN has a shareholder dividend reinvestment plan (the “Reinvestment Plan”) for registered holders of common shares of AQN. As at December 31, 2020, 160,934,788 common shares representing approximately 27% of total common shares outstanding had been registered with the Reinvestment Plan. During the three months ended December 31, 2020, 1,684,248 common shares were issued under the Reinvestment Plan, and subsequent to quarter-end, on January 15, 2021, an additional 1,403,635 common shares were issued under the Reinvestment Plan.
SHARE-BASED COMPENSATION PLANS
For the twelve months ended December 31, 2020, AQN recorded $24.6 million in total share-based compensation expense as compared to $11.0 million for the same period in 2019. The compensation expense is recorded as part of administrative expenses in the consolidated statement of operations, except for $12.6 million related to management succession and executive retirement expenses recorded in other net losses (see Note 19(b) in the consolidated financial statements). The portion of share-based compensation costs capitalized as cost of construction is insignificant.
As at December 31, 2020, total unrecognized compensation costs related to non-vested share-based awards was $12.1 million and is expected to be recognized over a period of 1.71.
Stock Option Plan
AQN 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.
AQN determines the fair value of options granted using the Black-Scholes option-pricing model. The estimated fair value of options, including the effect of estimated forfeitures, is recognized as an expense on a straight-line basis over the options’ vesting periods while ensuring that the cumulative amount of compensation cost recognized at least equals the value of the vested portion of the award at that date. During the twelve months ended December 31, 2020, the Company granted 999,962 options to executives of the Company. The options allow for the purchase of common shares at a weighted average price of C$16.78, the market price of the underlying common share at the date of grant. During the year ended December 31, 2020, executives of the Company exercised 2,386,275 stock options at a weighted average exercise price of C$12.52 in exchange for 748,786 common shares issued from treasury and 1,637,489 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, 2020, a total of 2,110,448 options were issued and outstanding under the stock option plan.
Performance and Restricted Share Units
AQN issues performance share units (“PSUs”) and restricted share units ("RSUs") to certain employees as part of AQN’s long-term incentive program. During the twelve months ended December 31, 2020, the Company granted (including dividends and performance adjustments) a combined total of 1,313,171 PSUs and RSUs to employees of the Company. During the twelve months ended December 31, 2020, the Company settled 968,470 PSUs, of which 507,611 PSUs were exchanged for common shares issued from treasury and 460,859 PSUs were settled at their cash value as payment for tax withholdings related to the settlement of the PSUs. Additionally, during the twelve months ended December 31, 2020, a total of 35,537 PSUs were forfeited.
As at December 31, 2020, a combined total of 2,721,207 PSUs and RSUs were granted and outstanding under the PSU and RSU plans.

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Directors' Deferred Share Units
AQN has a Directors' Deferred Share Unit Plan. Under the plan, non-employee directors of AQN receive all or any portion of their annual compensation in deferred share units (“DSUs”) and may elect to receive any portion of their remaining compensation in DSUs. The DSUs provide for settlement in cash or shares at the election of AQN. As AQN does not expect to settle the DSUs in cash, these DSUs are accounted for as equity awards. During the twelve months ended December 31, 2020, the Company issued 84,075 DSUs (including DSUs in lieu of dividends) to the directors of the Company.
As at December 31, 2020, a total of 544,493 DSUs had been granted under the DSU plan.
Bonus Deferral Restricted Share Units
The Company has a bonus deferral RSU program that is available to certain employees. The eligible employees have the option to receive a portion or all of their annual bonus payment in RSUs in lieu of cash. The RSUs provide for settlement in shares, and therefore these RSUs are accounted for as equity awards. During the twelve months ended December 31, 2020, 135,409 RSUs were issued (including RSUs in lieu of dividends) to employees of the Company. During the twelve months ended December 31, 2020, the Company settled 13,778 bonus RSUs, of which 6,401 were exchanged for common shares issued from treasury and 7,377 RSUs were settled at their cash value as payment for tax withholdings related to the settlement of the RSUs.
Employee Share Purchase Plan
AQN has an Employee Share Purchase Plan (the “ESPP”) which allows eligible employees to use a portion of their earnings to purchase common shares of AQN. The aggregate number of common shares reserved for issuance from treasury by AQN under this plan shall not exceed 4,000,000 shares. During the twelve months ended December 31, 2020, the Company issued 302,727 common shares to employees under the ESPP.
As at December 31, 2020, a total of 1,588,516 shares had been issued under the ESPP.
MANAGEMENT OF CAPITAL STRUCTURE
AQN views its capital structure in terms of its debt and equity levels at its individual operating groups and at an overall company level.
AQN’s objectives when managing capital are:
•To maintain its capital structure consistent with investment grade credit metrics appropriate to the sectors in which AQN operates;
•To maintain appropriate debt and equity levels 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.
AQN 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, AQN 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 into a number of transactions with equity-method investees in 2020 and 2019 (see Note 8 in the annual consolidated financial statements).
The Company provides administrative and development services to its equity-method investees and is reimbursed for incurred costs. To that effect, the Company charged its equity-method investees $25.8 million in 2020 as compared to $16.2 million during the same period in 2019. Additionally, one of the equity-method investees provides development services to the Company on specified projects, for which it earns a development fee upon reaching certain milestones.

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During 2020, the development fees charged to the Company were $26.0 million as compared to $3.9 million during the same period in 2019. See Note 8(e) and Note 8(f) in the annual consolidated financial statements.
In 2020, a subsidiary of the Company made a tax equity investment into Altavista Solar Subco, LLC, an equity investee of the Company and indirect owner of the Altavista Solar Project. Following the closing of the construction financing facility for the Altatvista Solar Project, certain excess funds were distributed to the Company and in return the Company issued a promissory note of $30.5 million payable to Altavista Solar Subco, LLC (See Note 8(e) and Note 12(j) in the annual consolidated financial statements).
On December 30, 2019, the Company and a third party each contributed C$1.5 million to the capital of a new joint venture, created for the purpose of investing in infrastructure opportunities. The Company sold its investment in Abengoa Water USA, LLC to the joint venture in exchange for a note receivable of $30.3 million (see Note 8(d) in the annual consolidated financial statements). No gain or loss was recognized on the sale. In 2019, AQN recorded interest income of $6.0 million, and a fair value loss of $6.0 million on its investment in the joint venture. On July 2, 2020, AQN acquired the third-party developer's 50% interest in the joint venture for C$1.6 million.
During 2019, 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 consolidated financial statements).
During 2019, 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 had an exclusive right of first offer for interests in certain renewable energy assets. The right expired in 2020.
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 consolidated financial statements). Redemption is not considered probable as at December 31, 2020. The Company incurred non-controlling interest attributable to AAGES of $12.7 million as compared to $16.5 million during the same period in 2019 and recorded distributions of $12.2 million as compared to $18.2 million during the same period in 2019 (see Note 17 in the annual consolidated financial statements). The subsidiary of Abengoa that holds the interest in AAGES is currently taking steps towards executing a restructuring plan which is subject to final creditor approval. In the event this restructuring is not successful, AQN would consolidate its interest in the preference share held by AAGES and the 3-year secured credit facility in the amount of $306.5 million ("AAGES Credit Facility")(see Joint Venture Risk).
On October 21, 2020, the Company paid $1.5 million to Abengoa for a twelve month exclusive, transferable, and irrevocable option to purchase all of Abengoa's interests in AAGES. During the term of the option, the Company is obligated to provide cash advances in an aggregate amount not exceeding $7.2 million in any calendar year to be used only in accordance with the baseline budget (see Note 8(e) in the annual 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. During 2020, the Company recorded distributions of $16.1 million as compared to $26.5 million during the same period in 2019.
The above related party transactions have been recorded at the exchange amounts agreed to by the parties to the transactions.

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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 ("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 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, strategic, 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. However, there can be no assurance that the Corporation's risk management activities will be successful in identifying, assessing, or mitigating the risks to which the Corporation is subject.
The risks discussed below are not intended as a complete list of all risks that AQN, its subsidiaries and affiliates are encountering or may encounter. Please see the Company's most recent AIF available on SEDAR and EDGAR for a further assessment of risk factors to which the Company is subject. To the extent of any inconsistency, the risks discussed below are intended to provide an update on those that were previously disclosed.
Risks Related to COVID-19
The COVID-19 situation remains fluid and its full impact on the Company’s business, financial condition, cash flows and results of operations is not fully known at this time. In addition to the risks and impacts described elsewhere in this MD&A, the COVID-19 pandemic and efforts to contain the virus could result in:
•operating, supply chain and project development and construction delays, disruptions and cost overruns;
•delayed collection of accounts receivable and increased levels of bad debt expense;
•delayed placed-in-service dates for the Company's renewable energy projects, which may give rise to, among other things, lower than anticipated revenue, delay-related liabilities to contractual counterparties and increased amounts of interest payable to construction lenders;
•reduced availability of funding under construction loans and tax equity financing, which may require the Company to initially increase its funding and, if possible, directly realize the tax benefits;
•lower revenue from the Company’s utility operations, including as a result of decreased consumption by customers not covered by rate decoupling;
•negative impacts to the Company's existing and planned rate reviews, including non-recovery of certain costs incurred directly or indirectly as a result of the COVID-19 pandemic and delays in filing, processing and settlement of the reviews;
•introduction of new legislation, policies, rules or regulations that adversely impact the Company;
•labour shortages and shutdowns (including as a result of government regulation and prevention measures), reduced employee and/or contractor productivity, and loss of key personnel;
•inability to implement the Company’s growth strategy, including sourcing new acquisitions and completing previously-announced acquisitions;
•inability to carry out the Company’s capital expenditure plans on previously anticipated timelines;
•lower earnings from unhedged power generation as a result of lower wholesale commodity prices in energy markets;
•losses or liabilities resulting from default, delays or non-performance by either the Company or its counterparties under the Company’s contracts, including joint venture agreements, supply agreements, construction agreements, services agreements and power purchase and other offtake agreements;

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•lower revenue from the Company's power generation facilities as a result of system load reduction and related system directed curtailments;
•delay in the permitting process of certain development projects, affecting the timing of final investment decisions and start of construction dates;
•reduced ability of the Company and its employees to effectively respond to, or mitigate the effects of, another force majeure or other significant event;
•increased operating costs for emergency supplies, personal protective equipment, cleaning services, enabling technology and other specific needs in response to COVID-19, some of which may not be recovered through future rates;
•increased market volatility and lower pension plan returns which could adversely impact the valuation of the plan assets and future funding requirements for the Company's pension plans;
•deterioration in financial metrics and other factors that impact the Company’s credit ratings;
•inability to meet the requirements of the covenants in existing credit facilities;
•inability to access credit and capital markets on acceptable terms or at all, including to refinance maturing indebtedness;
•IT and operational technology system interruptions, loss of critical data and increased cybersecurity and privacy breaches due to “work from home” arrangements implemented by the Company;
•business disruptions and costs when "work from home" arrangements are reduced and a greater number of employees return to the office;
•losses to the Company caused by fluctuations and volatility in the trading price of Atlantica’s ordinary shares or reduction of the dividend paid to holders of Atlantica’s ordinary shares; and
•fluctuations and volatility in the trading price of the Company’s common shares and other securities, which could result in losses for the Company’s security holders.
The COVID-19 pandemic may also have the effect of heightening the other risks described herein and under the heading Enterprise Risk Factors in the Company’s most recent AIF. The adverse impacts of COVID-19 on the Company can be expected to increase the longer the pandemic and the related response measures persist.
Change in customer demand due to the COVID-19 Pandemic
AQN operates utility systems across 16 regulatory jurisdictions delivering electric, natural gas, water and waste water services to residential, commercial and industrial customers in the areas it serves. The COVID-19 pandemic and resulting business suspensions and shutdowns have changed consumption patterns of residential, commercial and industrial customers across all three modalities of utility services, including decreased consumption among certain commercial and industrial customers. Further, different regulatory jurisdictions provide different mechanisms to allow utilities to adapt to changes in demand including decoupling on a total revenue basis, decoupling on a weather adjusted basis, and fixed fee components in rates.
AQN has seen the impacts on consumption patterns reduce from their early peaks as the economy has started to re-open.
Since the length of the pandemic, any longer term economic impacts, and how these may change consumption for residential, commercial and industrial customers is not known, the actual impacts on the Company’s operations for 2021 are not known at this time.
Risks Related to Changes in Laws and Regulations
The operations and activities of the Company, its subsidiaries and its business units are subject to the laws, regulations, orders and other requirements of a variety of federal, state, provincial and local governments, including regulatory commissions, environmental agencies and other regulatory bodies, which laws, regulations, orders and other requirements affect the operations and activities of, and costs incurred by, the Company. The Company is accordingly subject to risks associated with changing political conditions and changes in, modifications to, or reinterpretations of, existing laws, orders or regulations, and the imposition of new laws, orders or regulations (including, without limitation, the proposed legislation presented by the Governor of the State of New York to the New York Legislature on November 4, 2020 entitled "An Act to Reform the Enforcement Oversight and Franchise Revocation Process for Public Utilities"), any of which could adversely affect the Company’s business, regulatory approvals, assets, results of operations and financial condition. If the Company or any of its subsidiaries or business units were found to be in violation of applicable laws, regulations, orders or other requirements, they could be subject to significant penalties or legal actions.

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Treasury Risk Management
Downgrade in the Company's Credit Rating Risk
AQN has a long term consolidated corporate credit rating of BBB from S&P, a BBB rating from DBRS and a BBB issuer rating from Fitch. APCo, the parent company for the U.S. and Canadian generating assets under the Renewable Energy Group, has a BBB issuer 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, BBB+ from Fitch and BBB from S&P. 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 AQN’s or its subsidiaries' issuer corporate credit ratings would result in an increase in AQN’s borrowing costs under its bank credit facilities and future long-term debt securities issued. Any such downgrade could also adversely impact the market price of the outstanding securities of the Company, could impact the Company's ability to acquire additional regulated utilities and could require the Company to post additional collateral security under some of its contracts and hedging arrangements. If any of AQN’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), AQN’s ability to issue short-term debt or other securities or to market those securities would be constrained or made more difficult or expensive. Therefore, any such downgrades could have a material adverse effect on AQN’s business, cost of capital, financial condition and results of operations.
The Company is not adopting or endorsing such ratings, and such ratings do not indicate AQN’s assessment of its own ability to pay the interest or principal of debt securities it issues. The Company is providing such ratings only to assist with the assessment of future risks and effects of ratings on the Company’s financing costs.
No assurances can be provided that any of AQN'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 AQN to adjust its business and strategy in order to maintain its credit ratings. AQN currently anticipates that to continue to maintain a BBB flat investment grade credit 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 AQN’s Regulated Services Group. There can be no assurance that AQN will be successful, and the failure to do so could have a negative impact on AQN’s credit ratings. The business mix target may from time to time require AQN to grow its Regulated Services Group or implement other strategies in order to pursue investment opportunities within its Renewable Energy Group.
Capital Markets and Liquidity Risk
As at December 31, 2020, the Company had approximately $4,538.8 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 and which may be impacted by the risk factors herein. 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

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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 AQN 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. AQN does not actively manage interest rate risk on its variable interest rate borrowings due to the primarily short term and revolving nature of the amounts drawn.
Based on amounts outstanding as at December 31, 2020, 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 $155.0 million outstanding as at December 31, 2020. As a result, a 100 basis point change in the variable rate charged would impact interest expense by $1.6 million annually;
•the Corporate Liquidity Facility is subject to a variable interest rate and had no amounts outstanding as at December 31, 2020. As a result, a 100 basis point change in the variable rate charged would not impact interest expense;
•the Regulated Services Credit Facility is subject to a variable interest rate and had no amounts outstanding as at December 31, 2020. As a result, a 100 basis point change in the variable rate charged would not impact interest expense;
•the Regulated Services Liquidity Facility is subject to a variable interest rate and had no amounts outstanding as at December 31, 2020. As a result, a 100 basis point change in the variable rate charged would not impact interest expense;
•the BELCO Credit Facility is subject to a variable interest rate and had $68.5 million outstanding as at December 31, 2020. As a result, a 100 basis point change in the variable rate charged would impact interest expense by $0.7 million annually;
•the Regulated Services Group's commercial paper program is subject to a variable interest rate and had $122.0 million outstanding as at December 31, 2020. As a result, a 100 basis point change in the variable rate charged would impact interest expense by $1.2 million annually;
•the Renewable Energy Credit Facility is subject to a variable interest rate and had no amounts outstanding as at December 31, 2020. As a result, a 100 basis point change in the variable rate charged would not impact interest expense; and
•term facilities at BELCO and ESSAL that are subject to variable interest rates had $152.3 million outstanding as at December 31, 2020. As a result, a 100 basis point change in the variable rate charged would impact interest expense by $1.5 million annually.

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Foreign Currency Risk
The functional currency of most of AQN's operations is the U.S. dollar, however AQN is exposed to currency fluctuations from its Canadian and Chilean operations.
AQN may enter into derivative contracts to hedge all or a portion of currency exchange rate exposure that is transactional in nature and where a natural economic hedge does not exist (see Note 24 (b)(iii) in the annual consolidated financial statements). To the extent that the Company does enter into currency hedges, the Company may not realize the full benefits of favourable exchange rate movement, and is subject to risks that the counterparty to the hedging contracts may prove unable or unwilling to perform their obligations under the contracts.
Canadian operations
The Company is exposed to currency fluctuations from its Canadian-based operations. AQN manages this risk primarily through the use of natural hedges by using long-term debt in Canadian Dollars to finance its Canadian operations and a combination of foreign exchange forward contracts and spot purchases.
Chilean operations
The Company is exposed to currency fluctuations from its Chilean-based operations. AQN manages this risk primarily through the use of natural hedges by using long-term debt in Chilean pesos or indexed to the Chilean Peso to finance its Chilean operations. The Company's Chilean operations are determined to have the Chilean peso as their functional currency.
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 certain renewable power generation facilities that begin construction before 2024, 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.
Credit/Counterparty Risk
AQN 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 Renewable Energy Group's revenues are approximately 15% of total Company revenues. Approximately 91% 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 $56.4 million which is spread over approximately 409,000 customer connections, resulting in an average outstanding balance of approximately $140 dollars per customer connection.
The natural gas distribution systems accounts receivable balances related to the natural gas utilities total $93.3 million, while electric distribution systems accounts receivable balances related to the electric utilities total $123.7 million. The natural gas and electrical utilities both derive over 85% of their revenue from residential customers and have a per customer connection average outstanding balance of $252 dollars and $404 dollars respectively.

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Adverse conditions in the energy industry or in the general economy including the effects of the COVID-19 pandemic, 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.
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 Senate, Sandy Ridge and Minonk Wind Facilities have entered into financial hedges that end between 2027 and 2028. The financial hedges are structured to hedge an average of approximately 61% of annual LTAR against exposure to the applicable hub current spot market rates. The average unhedged production based on LTAR is approximately 419 GW-hrs annually.
The Sugar Creek Wind Facility has a financial hedge in place until the end of 2030 which is structured to hedge an average of 74% of annual LTAR against exposure to the applicable hub current spot market rates. The average unhedged production based on LTAR is approximately 188 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, 2020, the Renewable Energy Group had entered into hedges with a cumulative notional quantity of 372,926 MW-hrs.
The Company has elected the fair value option under ASC 825, Financial Instruments to account for its investment in Atlantica, with changes in fair value reflected in the annual consolidated statement of operations. As a result, each dollar change in the traded price of Atlantica shares will correspondingly affect the Company's Net Earnings by approximately $44.9 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 representative discussion of these risks is set out as follows:
Regulated Services Group
The CalPeco Electric System provides electric service to the Lake Tahoe California basin and surrounding areas at rates approved by the CPUC. The CalPeco Electric System purchases the energy, capacity, and related service requirements for its customers from NV Energy via a PPA at rates reflecting NV Energy’s system average costs.
The CalPeco Electric System's tariffs allow for the pass-through of energy costs to its rate payers on a dollar for dollar basis, through the Energy Cost Adjustment Clause ("ECAC") mechanism, which allows for the recovery or refund of changes in energy costs that are caused by the fluctuations in the price of fuel and purchased power. On a monthly basis, energy costs are compared to the CPUC approved base tariff energy rates and the difference is deferred to a balancing account. Annually, based on the balance of the ECAC balancing account, if the ECAC revenues were to increase or decrease by more

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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 periodically by the NHPUC through Least Cost Integrated Resource Plan filings which typically are filed bi-annually but can be as long as a five-year interim period depending on the length of the review process. In addition, EnergyNorth Natural Gas System files with the NHPUC for recovery of its transportation and commodity costs on an annual basis through the Cost of Gas ("COG") filing and approval process. The EnergyNorth Natural Gas System establishes rates for its customers based on the NHPUC's approval of its filed COG. These rates are designed to fully recover its anticipated transportation and commodity costs. In order to minimize commodity price fluctuations, the EnergyNorth Natural Gas System locks in a fixed price basis for approximately 16% of its normal winter period purchases under a NHPUC approved hedging program. All costs associated with the fixed basis hedging program are allowed to be a pass-through to customers through the COG filing and the approved rates in said filing. Should commodity prices increase or decrease relative to the initial annual COG rate filing, the EnergyNorth Natural Gas System has the right to automatically adjust its COG rates going forward up to 25% in order to minimize any under or over collection of its gas costs. In addition, any under collections may be carried forward with interest to the next year’s corresponding COG period, i.e. winter to winter and summer to summer.
The Midstates Gas and Empire Gas Systems purchases pipeline capacity, storage and commodity from a variety of counterparties, and files with the three individual state commissions for recovery of their respective transportation and commodity costs through an annual Purchase Gas Adjustment (“PGA”) filing and approval process. The Midstates Gas Systems serves customers in Missouri, Illinois and Iowa and establishes rates for its customers within the PGA filing in each state and these rates are designed to fully recover its anticipated transportation, storage and commodity costs. In order to minimize commodity price fluctuations, the Midstates Gas System has implemented a commodity hedging program, consistent with regulator expectations and approvals, designed to hedge approximately 25-50% of its non-storage related commodity purchases. All gains and losses associated with the hedging program are allowed to be a pass-through to customers through the PGA filing and are embedded in the approved rates in said filing. Rates can be adjusted on a monthly or quarterly basis in order to account for any commodity price increase or decrease relative to the initial PGA rate, minimizing any under or over collection of its 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 allowed to be a pass through to customers in the PGA. The Empire Gas System is permitted to file an Actual Cost Adjustment (“ACA”) once a year which also includes a PGA filing. In addition to the ACA filing, three more optional PGA filings are allowed during the year. The Empire Gas 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 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

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over/under variances associated with the hedging program are passed through to customers in the fuel adjustment clause assuming they are deemed to be prudently incurred.
BELCO purchases Heavy Fuel Oil (HFO), Light Fuel Oil (LFO) and diesel which are transported and stored in facilities in Bermuda until such time as they are delivered and consumed in its electricity generation operations. While the cost of this fuel is included in traditional rate filings through a Fuel Adjustment Rate (“FAR”), the variability in the commodity pricing has led the Regulatory Authority of Bermuda to establish a quarterly reconciliation and adjustment to the FAR. This filing evaluates current commodity pricing and usage as well as projected commodity pricing to develop the FAR for the upcoming quarter. Additionally, BELCO has periodically used hedging to lock in commodity rates in an effort to reduce pricing volatility and protect customer rates.
Renewable Energy Group
The Sanger Thermal Facility’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 $0.5 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 2021, 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 57,000 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 57,000 MW-hrs is mitigated through the use of financial energy hedge contracts which cover approximately 45,000 MW-hrs of the Maritime region's anticipated purchases during the year at an average rate of approximately $40 per MW-hr.
OPERATIONAL RISK MANAGEMENT
Mechanical and Operational Risks
AQN's profitability could be impacted by, among other things, equipment failure, the failure of a major customer to fulfill its contractual obligations under its PPA, reductions in average energy prices, a strike or lock-out at a facility, natural disasters, diseases (including COVID-19) 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. Wildfires may occur within the Regulated Services Group’s electric distribution service territories, including, without limitation, in California and the southern United States, such as the Mountain View fire that occurred on November 17, 2020, within the CalPeco Electric System’s service territory in California. In forested areas, trees falling on and lightning strikes to, distribution lines or equipment, can ignite wildfires which may pose a risk to life and property. If the Company is accused or found to be responsible for such a fire, the Company could suffer costs, losses and damages, including inverse condemnation, all or some of which may not be recoverable through insurance, legal, regulatory recovery and other processes.
The Regulated Services Group's natural gas distribution systems are subject to risks which may lead to fire and/or explosion which may impact life and property. Risks include third party damage, compromised system integrity, type/age of pipelines, and severe weather events.
The 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

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generators failures is mitigated by properly maintaining the units, using long term maintenance agreements with the turbine O&Ms which provide for regular inspections and maintenance of property, and liability insurance policies.
The 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 AQN’s operations, both operationally and geographically, the use of regular maintenance programs, including pipeline safety programs and compliance programs, maintaining adequate insurance, an active Enterprise Risk Management program and the establishment of reserves for expenses.
Regulatory Risk
Profitability of AQN businesses is, in part, dependent on regulatory climates in the jurisdictions in which those businesses operate. In the case of some of Renewable Energy Group's hydroelectric facilities, water rights are 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 its regulatory agencies. The Regulated Services Group operates in 13 U.S. states, 1 Canadian province, Bermuda and Chile and therefore is subject to regulation from 17 different regulatory agencies including FERC. The time between the incurrence of costs and the granting of the rates to recover those costs by regulatory agencies is known as regulatory lag. As a result of regulatory lag, inflationary effects and timing delays may impact the ability to recover expenses and/or capital costs, and profitability could be impacted. In order to mitigate this exposure, the Regulated Services Group seeks to obtain approval for regulatory constructs in the states in which it operates to allow for timely recovery of operating expenses and capital costs. A fundamental risk faced by any regulated utility is the disallowance of operating expenses or capital costs to be placed into its revenue requirement by the utility's regulator. In addition, capital investments that have become stranded may pose additional risk for cost recovery and could be subject to legislative proposals that would impact the extent to which such costs could be recovered. To the extent proposed costs are not included in the utility's revenue requirement, the utility will be required to find other efficiencies, growth opportunities or cost savings to achieve its allowed returns.
The Regulated Services Group regularly works with its governing authorities to manage the affairs of the business, employing both local, state level, and corporate resources.
Condemnation Expropriation Proceedings
The Regulated Services Group's distribution systems could be subject to condemnation or other methods of taking by government entities under certain conditions. Any taking by government entities would legally require fair compensation to be paid. Determination of such fair compensation is undertaken pursuant to a legal proceeding and, therefore, there is no assurance that the value received for assets taken will be in excess of book value.
Apple Valley Condemnation Proceedings
Liberty Utilities (Apple Valley Ranchos Water) Corp ("Liberty Apple Valley") 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. The evidentiary portion of the right-to-take condemnation trial finished on July 15, 2020 and a decision is expected from the Court in the first half of 2021. If Liberty Apple Valley prevails, the case is concluded and the Town may 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 lawsuit 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. Any taking by the 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.
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.

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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 AQN 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 AQN 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 operates in markets, or may pursue growth opportunities in new markets, that are subject to regulation by various foreign governments and regulatory authorities and to the application of foreign laws. Such foreign laws or regulations may not provide the same type of legal certainty and rights, in connection with the Company’s contractual relationships in such countries, as are afforded to the Company in Canada and the U.S., which may adversely affect the Company’s ability to receive revenues or enforce its rights in connection with any operations or projects in such jurisdictions. In addition, the laws and regulations of some countries may limit the Company’s ability to hold a majority interest in certain projects, thus limiting the Company’s ability to control the operations of such projects. Any existing or new operations or interests of the Company may also be subject to significant political, economic and financial risks, which vary by country, and may include: (i) changes in government laws, policies or personnel; (ii) changes in general economic conditions; (iii) restrictions on currency transfer or convertibility; (iv) changes in labour relations; (v) political instability and civil unrest; (vi) regulatory or other changes adversely affecting the local utility market; (vii) breach or repudiation of important contractual undertakings and expropriation and confiscation of assets and facilities without compensation or compensation that is less than fair market value; (viii) less developed or efficient financial markets than in North America; (ix) the absence of uniform accounting, auditing and financial reporting standards, practices and disclosure requirements; (x) less government supervision and regulation; (xi) a less developed legal or regulatory environment, including uncertainty in outcomes and actions that may be inconsistent with the rule of law; (xii) heightened exposure to corruption risk; (xiii) political hostility to investments by foreign investors, including laws affecting foreign ownership; (xiv) less publicly available information in respect of companies; (xv) adversely higher or lower rates of inflation; (xvi) higher transaction costs; and (xvii) fewer investor protections.
The Company may suffer a significant loss resulting from fraud, bribery, corruption or other illegal acts, or from inadequate or failed internal processes or systems. The Company operates in multiple jurisdictions and it is possible that its operations and development activities will expand into new jurisdictions. Doing business in multiple jurisdictions requires the Company to comply with the laws and regulations of such jurisdictions. These laws and regulations may apply to the Company, its subsidiaries, individual directors, officers, employees and third-party agents. The Company is also subject to anti-bribery and anti-corruption laws, including the Canadian Corruption of Foreign Public Officials Act and the U.S. Foreign Corrupt Practices Act. As the Company makes acquisitions and pursues development activities internationally, it is exposed to increased corruption-related risks, including potential violations of applicable anti-corruption laws.
The Company relies on its infrastructure, controls, systems and personnel, as well as central groups focusing on enterprise-wide management of specific operational risks such as fraud, trading, outsourcing, and business disruption, to manage the risk of illegal and corrupt acts or failed systems. The Company also relies on its employees and certain third parties to comply with its policies and processes as well as applicable laws. The failure to adequately identify or manage these risks, and the acquisition of businesses with weak internal controls to manage the risk of illegal or corrupt acts, could result in direct or indirect financial loss, regulatory censure and/or harm to the Company’s reputation.
Risks Specific to the Atlantica Investment
The Company’s investment in Atlantica exposes the Company to certain risks that are particular to Atlantica’s business and the markets in which Atlantica operates.
Atlantica owns, manages and acquires renewable energy, conventional power, electric transmission lines and water assets in certain jurisdictions where the Company may not operate. The Company, through its investment in Atlantica, is indirectly exposed to certain risks that are particular to the markets in which it operates, including, but not limited to, risks related to: conditions in the global economy; changes to national and international laws, political, social and macroeconomic risks relating to the jurisdictions in which Atlantica operates, including in emerging markets, which could be subject to economic, social and political uncertainties; anti-bribery and anti-corruption laws and substantial penalties and reputational damage from any non-compliance therewith; significant currency exchange rate fluctuations; Atlantica’s ability to identify and/or consummate future acquisitions on favourable terms or at all; Atlantica’s inability to replace, on similar or commercially favourable terms, expiring or terminated offtake agreements; termination or revocation of

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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 accounts for its investment in Atlantica using the Fair Value Method (see Note 8(a) in the annual consolidated financial statements). AQN records in the consolidated statements of operations the fluctuations in the fair value of Atlantica shares and dividend income when it is declared.
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. The AAGES Credit Facility is collateralized through a pledge of 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 such 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 subsidiary of Abengoa that holds the interest in AAGES is currently taking steps towards executing a restructuring plan which is subject to final creditor approval. In the event this restructuring is not successful, AQN would consolidate its interest in the preference share held by AAGES and the AAGES Credit Facility.
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 consolidated financial statements for a description of the Company's Long Term Investments and Notes Receivable.
Asset Retirement Obligations
AQN and its subsidiaries complete periodic reviews of potential asset retirement obligations that may require recognition. As part of this process, AQN and its subsidiaries consider the contractual requirements outlined in their operating permits, leases, and other agreements, the probability of the agreements being extended, the ability to quantify such expense, the timing of incurring the potential expenses, as well as other factors which may be considered in evaluating if such obligations exist and in estimating the fair value of such obligations.
In conjunction with acquisitions and developed projects, the Company assumed certain asset retirement obligations. The asset retirement obligations mainly relate to legal requirements for: (i) removal or decommissioning of power generating facilities; (ii) cut (disconnect from the distribution system), purge (clean of natural gas and PCB contaminants), and cap 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.

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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.
There is a risk that climate change impacts the seasonality and demand for water, electricity and gas.
The Company attempts to mitigate the above noted risks by seeking regulatory mechanisms during rate review proceedings. While not all regulatory jurisdictions have approved mechanisms to mitigate demand fluctuations, to date, the Regulated Services Group has successfully obtained regulatory approval to implement such decoupling mechanisms in 7 of 13 states. An example of such a mechanism is seen at the Peach State Gas System in Georgia, where a weather normalization adjustment is applied to customer bills during the months of October through May that adjusts commodity rates to stabilize the revenues of the utility for changes in billing units attributable to weather patterns.
Renewable Energy Group
The Renewable Energy Group's hydroelectric operations are impacted by seasonal fluctuations and year to year variability of the available hydrology. These assets are primarily “run-of-river” and as such fluctuate with natural water flows. During the winter and summer periods, flows are generally lower while during the spring and fall periods flows are generally higher. The ability of these assets to generate income may be impacted by changes in water availability or other material hydrologic events within a watercourse. Year to year the level of hydrology varies, impacting the amount of power that can be generated in a year.
The Renewable Energy Group's wind generation facilities are impacted by seasonal fluctuations and year to year variability of the wind resource. During the fall 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 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.

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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. In the second quarter of 2020, the IRS extended by one year the “continuity safe harbor” deadline by which wind and solar projects must be placed in service to qualify for the maximum permissible PTC and ITC, respectively. The first step down is now set to occur on December 31, 2021.
In each of the jurisdictions where the Company's major renewable energy construction projects are located, construction of new renewable energy generation has been considered an essential activity exempt from government-mandated business shutdowns. As a result, construction activities have proceeded at all of the Company's major renewable energy construction projects throughout the COVID-19 pandemic.
In February 2020, AQN received force majeure notices or similar notices from suppliers and/or contractors for all of its major renewable energy construction projects. Certain manufacturing, transportation and delivery delays have occurred, and similar future disruptions are possible due to COVID-19, however the anticipated placed-in-service dates for the Company’s major renewable energy construction projects have not been materially impacted by COVID-19 to date. The Company expects that all of its U.S. wind and solar projects currently under construction will qualify for the maximum PTC and ITC, respectively.
As a result of a blade manufacturing error, the Renewable Energy Group was instructed by its turbine supplier on November 24, 2020 to shut down 26 turbines at the Maverick Creek Wind Facility and 26 turbines at the Sugar Creek Wind Facility. Correction of this issue requires remediating 45 affected blades at the Maverick Creek Wind Facility and 38 affected blades at the Sugar Creek Wind Facility. The Renewable Energy Group has been working closely with the turbine supplier on this issue and expects the remediation work to be completed in the third quarter of 2021. The relevant turbine supply and operating agreements contain customary protections in favour of the Company relating to the replacement of the affected blades and the associated impacts due to operating down time.
Litigation Risks and Other Contingencies
AQN and certain of its subsidiaries are involved in various litigation, claims and other legal and regulatory proceedings that arise from time to time in the ordinary course of business. Any accruals for contingencies related to these items are recorded in the financial statements at the time it is concluded that a material financial loss is likely and the related liability is estimable. Anticipated recoveries under existing insurance policies are recorded when reasonably assured of recovery.
Claim by Gaia Power Inc.
On October 30, 2018, Gaia Power Inc. (“Gaia”) commenced an action in the Ontario Superior Court of Justice against AQN and certain of its subsidiaries, initially claiming damages of not less than C$345 million and punitive damages in the sum of C$25 million. On November 28, 2020, Gaia served the Company with an amended notice of arbitration to, among other things, lower the value of its damages claim to C$108.5 million and lower the value of its punitive damages claim to C$10 million. The action arises from Gaia’s 2010 sale, to a subsidiary of AQN, 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 agreed to arbitrate the dispute, with the evidentiary portion of the hearing having occurred during the week of February 22, 2021 and closing arguments scheduled for March 16 and 17, 2021. The likelihood of success in this lawsuit cannot be reasonably predicted; however, AQN intends to continue to vigorously defend it.
Mountain View Fire
On November 17, 2020, a wildfire now known as the Mountain View fire occurred in the territory of Liberty Utilities (CalPeco Electric) LLC. The cause of the fire is undetermined at this time, and CAL FIRE has not yet issued a report. To date, four lawsuits have been filed against subsidiaries of the Company in connection with the Mountain View fire. Three of these lawsuits are brought by groups of individual plaintiffs alleging causes of action including negligence, inverse condemnation, nuisance, trespass, and violations of Cal. Pub. Util. Code 2106 and Cal. Health and Safety Code 13007. In the fourth lawsuit, County of Mono, Antelope Valley Fire Protection District, Toiyabe Indian Health Project, and Bridgeport Indian Colony allege similar causes of action and seek damages for fire suppression costs, law enforcement costs, property

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and infrastructure damage, and other costs. The likelihood of success in these lawsuits cannot be reasonably predicted; however, the Company intends to vigorously defend them.
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.
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.

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QUARTERLY FINANCIAL INFORMATION
The following is a summary of unaudited quarterly financial information for the eight quarters ended December 31, 2020:

(all dollar amounts in $ millions except per share information) | 1st Quarter 2020 |  | 2nd Quarter 2020 |  | 3rd Quarter 2020 |  | 4th Quarter 2020
Revenue | $ | 465.0 |  |  | $ | 343.6 |  |  | $ | 376.1 |  |  | $ | 492.4 |
Net earnings (loss) attributable to shareholders | (63.8) |  |  | 286.2 |  |  | 55.9 |  |  | 504.2 |
Net earnings (loss) per share | (0.13) |  |  | 0.54 |  |  | 0.09 |  |  | 0.84 |
Diluted net earnings (loss) per share | (0.13) |  |  | 0.53 |  |  | 0.09 |  |  | 0.83 |
Adjusted Net Earnings 1 | 103.3 |  |  | 47.4 |  |  | 88.1 |  |  | 127.0 |
Adjusted Net Earnings per share 1 | 0.19 |  |  | 0.09 |  |  | 0.15 |  |  | 0.21 |
Adjusted EBITDA 1 | 242.2 |  |  | 176.3 |  |  | 197.9 |  |  | 253.1 |
Total assets | 10,900.6 |  |  | 11,188.0 |  |  | 11,739.9 |  |  | 13,223.9 |
Long term debt 2 | 4,205.1 |  |  | 4,155.1 |  |  | 3,978.0 |  |  | 4,538.8 |
Dividend declared per common share | $ | 0.14 |  |  | $ | 0.16 |  |  | $ | 0.16 |  |  | $ | 0.16 |
| 1st Quarter 2019 |  | 2nd Quarter 2019 |  | 3rd Quarter 2019 |  | 4th Quarter 2019
Revenue | $ | 477.2 |  |  | $ | 343.6 |  |  | $ | 365.6 |  |  | $ | 440.0 |
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 Earnings 1 | 94.0 |  |  | 54.5 |  |  | 69.2 |  |  | 103.6 |
Adjusted Net Earnings per share 1 | 0.19 |  |  | 0.11 |  |  | 0.14 |  |  | 0.20 |
Adjusted EBITDA 1 | 231.3 |  |  | 190.0 |  |  | 186.9 |  |  | 230.4 |
Total assets | 9,671.3 |  |  | 10,034.3 |  |  | 10,618.9 |  |  | 10,920.8 |
Long term debt 2 | 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 |

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 $492.4 million over the prior two year period. A number of factors impact quarterly results including acquisitions, seasonal fluctuations, and winter and summer rates built into the PPAs. In addition, a factor impacting revenues year over year is the fluctuation in the strength of the Canadian dollar relative to the U.S. dollar which can result in significant changes in reported revenue from Canadian operations.
Quarterly net earnings attributable to shareholders have fluctuated between a loss of $63.8 million and earnings of $504.2 million over the prior two year period. Earnings have been significantly impacted by non-cash factors such as deferred tax recovery and expense, impairment of intangibles, property, plant and equipment and mark-to-market gains and losses on financial instruments.

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SUMMARY FINANCIAL INFORMATION OF ATLANTICA
The Company owns a 44.2% beneficial stake in Atlantica. AQN accounts for its interest in Atlantica using the fair value method (see Note 8(a) in the annual consolidated financial statements). The summary financial information of Atlantica in the following table is derived from the consolidated financial statements of Atlantica as of December 31, 2020 and 2019 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) | 2020 |  | 2019
Revenue | $ | 1,013.3 |  |  | $ | 1,011.5 |
Profit for the year | 16.9 |  |  | 74.6 |
Total non-current assets | 8,514.1 |  |  | 8,540.6 |
Total current assets | 1,424.3 |  |  | 1,119.2 |
Total non-current liabilities | 7,714.2 |  |  | 6,971.6 |
Total current liabilities | 483.3 |  |  | 973.4 |

DISCLOSURE CONTROLS AND PROCEDURES
AQN's management carried out an evaluation as of December 31, 2020, under the supervision of and with the participation of AQN’s Chief Executive Officer ("CEO") and Chief Financial Officer ("CFO"), of the effectiveness of the design and operations of AQN’s disclosure controls and procedures (as defined in Rule 13a-15(e) and Rule 15d-15 (e) under the Securities Exchange Act of 1934, as amended (the “Exchange Act”)). Based on that evaluation, the CEO and the CFO have concluded that as of December 31, 2020, AQN’s disclosure controls and procedures are effective to provide reasonable assurance that information required to be disclosed by AQN in reports that it files or submits under the Exchange Act is recorded, processed, summarized, and reported within the time periods specified in 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.
During the year ended December 31, 2020, the Company acquired Ascendant and ESSAL. Management is in the process of evaluating the existing controls and procedures of Ascendant and ESSAL and integrating financial reporting and controls for Ascendant and ESSAL 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 consolidated financial statements. As permitted under applicable laws and 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, 2020 (representing approximately 8% of AQN’s total assets as of December 31, 2020 and approximately 3% of AQN’s revenues for the year ended December 31, 2020). Management assessed the effectiveness of the Company's internal control over financial reporting as of December 31, 2020, 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, 2020 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 AQN.

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CHANGES IN INTERNAL CONTROLS OVER FINANCIAL REPORTING
For the twelve months ended December 31, 2020, there has been no change in the Company’s internal controls over financial reporting that has materially affected, or is reasonably likely to materially affect, the Company’s internal controls over financial reporting.
INHERENT LIMITATIONS ON EFFECTIVENESS OF CONTROLS
Due to its inherent limitations, disclosure controls and procedures or internal control over financial reporting may not prevent or detect all misstatements based on error or fraud. Further, the effectiveness of internal control is subject to the risk that controls may become inadequate because of changes in conditions, or that the degree of compliance with policies or procedures may change.
CRITICAL ACCOUNTING ESTIMATES AND POLICIES
AQN prepared its 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.
AQN’s significant accounting policies and new accounting standards are discussed in Notes 1 and 2 in the annual consolidated financial statements, respectively. Management believes the following accounting policies involve the application of critical accounting estimates. Accordingly, these accounting estimates have been reviewed and discussed with the Audit Committee of the Board of Directors of AQN.
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 most utility assets are subject to regulatory review and approval, and depreciation expense is recovered through rates set by ratemaking authorities. The recovery of those costs is dependent on the ratemaking process.
The carrying value of long-lived assets, including intangible assets and goodwill, is reviewed whenever events or changes in circumstances indicate that such carrying values may not be recoverable, and at least annually for goodwill. Some of the factors AQN considers as indicators of impairment include a significant change in operational or financial performance, unexpected outcome from rate orders, natural disasters, energy pricing and changes in regulation. When such events or circumstances are present, the Company assesses whether the carrying value will be recovered through the expected future cash flows. If the facility includes goodwill, the fair value of the facility is compared to its carrying value. Both methodologies are sensitive to the forecasted cash flows and in particular energy prices, long-term growth rate and, discount rate for the fair value calculation.
In 2020 and 2019, Management assessed qualitative and quantitative factors for each of the reporting units that were allocated goodwill. No goodwill impairment provision was required.

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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, with the exception of ESSAL.
Certain expenses and revenues subject to utility regulation or rate determination normally reflected in income are deferred on the balance sheet as regulatory assets or liabilities and are recognized in income as the related amounts are included in service rates and recovered from or refunded to customers. Regulatory assets and liabilities are recorded when it is probable that these items will be recovered or reflected in future rates. Determining probability requires significant judgment on the part of management and includes, but is not limited to, consideration of testimony presented in regulatory hearings, proposed regulatory decisions, final regulatory orders and industry practice. If events were to occur that would make the recovery of these assets and liabilities no longer probable, these regulatory assets and liabilities would be required to be written off or written down.
Unbilled Energy Revenues
Revenues related to natural gas, electricity and water delivery are generally recognized upon delivery to customers. The determination of customer billings is based on a systematic reading of meters throughout the month. At the end of each month, amounts of natural gas, energy or water provided to customers since the date of the last meter reading are estimated, and the corresponding unbilled revenue is recorded. Factors that can impact the estimate of unbilled energy include, but are not limited to, seasonal weather patterns compared to normal, total volumes supplied to the system, line losses, economic impacts, and composition of customer classes. Estimates are reversed in the following month and actual revenue is recorded based on subsequent meter readings.
Derivatives
AQN uses derivative instruments to manage exposure to changes in commodity prices, foreign exchange rates, and interest rates. Management’s judgment is required to determine if a transaction meets the definition of a derivative and, if it does, whether the normal purchases and sales exception applies or whether individual transactions qualify for hedge accounting treatment. Management’s judgment is also required to determine the fair value of derivative transactions. AQN determines the fair value of derivative instruments based on forward market prices in active markets obtained from external parties adjusted for nonperformance risk. A significant change in estimate could affect AQN’s results of operations if the hedging relationship was considered no longer effective.
Pension and Post-employment Benefits
The obligations and related costs of defined benefit pension and post-employment benefit plans are calculated using actuarial concepts, which include critical assumptions related to the discount rate, mortality rate, compensation increase, expected rate of return on plan assets and medical cost trend rates. These assumptions are important elements of expense and/or liability measurement and are updated on an annual basis, or upon the occurrence of significant events. The Company used the new mortality improvement scale (MP-2020) recently released by the Society of Actuaries adjusted to reflect the 2020 Social Security Administration ultimate improvement rates.

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The sensitivities of key assumptions used in measuring accrued benefit obligations and benefit plan cost for 2020 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.

| 2020 Pension Plans |  | 2020 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 | (91.3) |  |  | (4.0) |  |  |  | (45.0) |  |  | (2.9) |  |
1% decrease | 113.6 |  |  | 5.8 |  |  |  | 58.3 |  |  | 4.3 |  |
Future compensation rate |  |  |  |  |
1% increase | 4.0 |  |  | 2.2 |  |  |  | — |  |  | — |  |
1% decrease | (3.5) |  |  | (2.1) |  |  |  | — |  |  | — |  |
Expected return on plan assets |  |  |  |  |
1% increase | — |  |  | (5.8) |  |  |  | — |  |  | (1.4) |  |
1% decrease | — |  |  | 5.8 |  |  |  | — |  |  | 1.4 |  |
Health care trend |  |  |  |  |
1% increase | — |  |  | — |  |  |  | 52.2 |  |  | 5.3 |  |
1% decrease | — |  |  | — |  |  |  | (41.0) |  |  | (4.6) |  |

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

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