EX-99.3 4 a2019q4-exhibit993xmda.htm EXHIBIT 99.3 2019 Q4 MD&A
Management Discussion & Analysis
Management of Algonquin Power & Utilities Corp. (“APUC” or the “Company” or the “Corporation”) has prepared the following discussion and analysis to provide information to assist its shareholders’ understanding of the financial results for the three and twelve months ended December 31, 2019. This Management Discussion & Analysis (“MD&A”) should be read in conjunction with APUC’s annual audited consolidated financial statements for the years ended December 31, 2019 and 2018. This material is available on SEDAR at www.sedar.com, on EDGAR at www.sec.gov/edgar, and on the APUC website at www.AlgonquinPowerandUtilities.com. Additional information about APUC, including the most recent Annual Information Form (“AIF”), can be found on SEDAR at www.sedar.com and on EDGAR at www.sec.gov/edgar.
Unless otherwise indicated, financial information provided for the years ended December 31, 2019 and 2018 has been prepared in accordance with generally accepted accounting principles in the United States (“U.S. GAAP”). As a result, the Company's financial information may not be comparable with financial information of other Canadian companies that provide financial information on another basis.
All monetary amounts are in thousands of U.S. dollars, except where otherwise noted. We denote any amounts denominated in Canadian dollars with "C$" immediately prior to the stated amount.
This MD&A is based on information available to management as of February 27, 2020.
Contents

Caution Concerning Forward-Looking Statements, Forward-Looking Information and non-GAAP Measures | 2
Overview and Business Strategy | 5
2019 Major Highlights | 7
2019 Fourth Quarter Results From Operations | 9
2019 Annual Results From Operations | 11
2019 Adjusted EBITDA Summary | 14
Regulated Services Group | 15
Renewable Energy Group | 21
APUC: Corporate and Other Expenses | 26
Non-GAAP Financial Measures | 28
Corporate Development Activities | 31
Summary of Property, Plant and Equipment Expenditures | 32
Liquidity and Capital Reserves | 34
Share-Based Compensation Plans | 37
Management of Capital Structure | 39
Related Party Transactions | 39
Enterprise Risk Management | 40
Quarterly Financial Information | 51
Summary Financial Information of Atlantica | 52
Disclosure Controls and Internal Controls Over Financial Reporting | 52
Critical Accounting Estimates and Policies | 53

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

Caution Concerning Forward-Looking Statements, Forward-Looking Information and Non-GAAP Measures
Forward-Looking Statements and Forward-Looking Information
This document may contain statements that constitute "forward-looking information" within the meaning of applicable securities laws in each of the provinces of Canada and the respective policies, regulations and rules under such laws or "forward-looking statements" within the meaning of the U.S. Private Securities Litigation Reform Act of 1995 (collectively, “forward-looking information”). The words “anticipates”, “believes”, “budget”, “could”, “estimates”, “expects”, “forecasts”, “intends”, “may”, “might”, “plans”, “projects”, “schedule”, “should”, “will”, “would” and similar expressions are often intended to identify forward-looking information, although not all forward-looking information contains these identifying words. Specific forward-looking information in this document includes, but is not limited to, statements relating to: expected future growth and results of operations; liquidity, capital resources and operational requirements; rate reviews, including resulting decisions and rates and expected impacts and timing; sources of funding, including adequacy and availability of credit facilities, debt maturation and future borrowings; expectations regarding the use of proceeds from equity financing, including the Offering and the ATM Program (each as defined herein); ongoing and planned acquisitions, projects and initiatives, including expectations regarding costs, financing, results and completion dates; expectations regarding the anticipated closing of APUC's acquisitions of Ascendant and New York American Water (each as defined herein); expectations regarding the Company's corporate development activities and the results thereof including the expected business mix between the Regulated Services Group and Renewable Energy Group; expectations regarding regulatory hearings, motions and approvals; expectations regarding the cost of operations, capital spending and maintenance, and the variability of those costs; expected future capital investments, including expected timing, investment plans, sources of funds and impacts; expectations regarding generation availability, capacity and production; expectations regarding the outcome of existing or potential legal and contractual claims and disputes; expectations regarding the ability to access the capital market on reasonable terms; strategy and goals; expectations regarding succession planning; contractual obligations and other commercial commitments; environmental liabilities; dividends to shareholders; expectations regarding the maturity and redemption of APUC's outstanding subordinated notes; expectations regarding the impact of tax reforms; credit ratings; anticipated growth and emerging opportunities in APUC’s target markets; accounting estimates; interest rates; currency exchange rates; and commodity prices. All forward-looking information is given pursuant to the “safe harbor” provisions of applicable securities legislation.
The forecasts and projections that make up the forward-looking information contained herein are based on certain factors or assumptions which include, but are not limited to: the receipt of applicable regulatory approvals and requested rate decisions; the absence of material adverse regulatory decisions being received and the expectation of regulatory stability; the absence of any material equipment breakdown or failure; availability of financing on commercially reasonable terms and the stability of credit ratings of the Corporation and its subsidiaries; the absence of unexpected material liabilities or uninsured losses; the continued availability of commodity supplies and stability of commodity prices; the absence of sustained interest rate increases or significant currency exchange rate fluctuations; the absence of significant operational or supply chain disruptions or liability due to natural disasters, diseases or catastrophic events; the continued ability to maintain systems and facilities to ensure their continued performance; the absence of a severe and prolonged downturn in general economic, credit, social and market conditions; the successful and timely development and construction of new projects; the absence of material capital project or financing cost overruns; sufficient liquidity and capital resources; the continuation of observed weather patterns and trends; the absence of significant counterparty defaults; the continued competitiveness of electricity pricing when compared with alternative sources of energy; the realization of the anticipated benefits of the Corporation’s acquisitions and joint ventures; the absence of a material change in political conditions or public policies and directions by governments materially negatively affecting the Corporation; the ability to obtain and maintain licenses and permits; the absence of a material decrease in market energy prices; the absence of material disputes with taxation authorities or changes to applicable tax laws; continued maintenance of information technology infrastructure and the absence of a material breach of cyber security; favourable relations with external stakeholders; and favourable labour relations.
The forward-looking information contained herein is subject to risks, uncertainties and other factors that could cause actual results to differ materially from historical results or results anticipated by the forward-looking information. Factors which could cause results or events to differ materially from current expectations include, but are not limited to: changes in general economic, credit, social and market conditions; changes in customer energy usage patterns and energy demand; global climate change; the incurrence of environmental liabilities; natural disasters and other catastrophic events; the failure of information technology infrastructure and cybersecurity; the loss of key personnel and/or labour disruptions; seasonal fluctuations and variability in weather conditions and natural resource availability; reductions in demand for electricity, gas and water due to developments in technology; reliance on transmission systems owned and operated by third parties; issues arising with respect to land use rights and access to the Corporation’s facilities; critical equipment breakdown or failure; terrorist attacks; fluctuations in commodity prices; capital expenditures; reliance on subsidiaries; the incurrence of an uninsured loss; a credit rating downgrade; an increase in financing costs or limits on access to credit and capital markets; sustained increases in interest rates; currency exchange rate fluctuations; restricted financial flexibility due to covenants in existing credit agreements; an

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

inability to refinance maturing debt on commercially reasonable terms; disputes with taxation authorities or changes to applicable tax laws; failure to identify, acquire, develop or timely place in service projects to maximize the value of production tax credit qualified equipment; requirement for greater than expected contributions to post-employment benefit plans; default by a counterparty; inaccurate assumptions, judgments and/or estimates with respect to asset retirement obligations; failure to maintain required regulatory authorizations; changes to health and safety laws, regulations or permit requirements; failure to comply with and/or changes to environmental laws, regulations and other standards; compliance with new foreign laws or regulations; failure to identify attractive acquisition or development candidates necessary to pursue the Corporation’s growth strategy; delays and cost overruns in the design and construction of projects, including as a result of the 2019 novel coronavirus outbreak in China (the "2019 Novel Coronavirus"); loss of key customers; failure to realize the anticipated benefits of acquisitions or joint ventures; Atlantica (as defined herein) or the Corporation’s joint venture with Abengoa S.A (MC:ABG) ("Abengoa"), Abengoa-Algonquin Global Energy Solutions ("AAGES"), acting in a manner contrary to the Corporation’s interests; a drop in the market value of Atlantica's ordinary shares; facilities being condemned or otherwise taken by governmental entities; increased external-stakeholder activism adverse to the Corporation’s interests; and fluctuations in the price and liquidity of the Corporation’s common shares. Although the Corporation has attempted to identify important factors that could cause actual actions, events or results to differ materially from those described in forward-looking information, there may be other factors that cause actions, events or results not to be as anticipated, estimated or intended. Some of these and other factors are discussed in more detail under the heading “Enterprise Risk Management” and in the Corporation's most recent AIF.
Forward-looking information contained herein is made as of the date of this document and based on the plans, beliefs, estimates, projections, expectations, opinions and assumptions of management on the date hereof. There can be no assurance that forward-looking information will prove to be accurate, as actual results and future events could differ materially from those anticipated in such forward-looking information. Accordingly, readers should not place undue reliance on forward-looking information. While subsequent events and developments may cause the Corporation’s views to change, the Corporation disclaims any obligation to update any forward-looking information or to explain any material difference between subsequent actual events and such forward-looking information, except to the extent required by law. All forward-looking information contained herein is qualified by these cautionary statements.
Non-GAAP Financial Measures
The terms “Adjusted Net Earnings”, “Adjusted Earnings Before Interest, Taxes, Depreciation and Amortization” (“Adjusted EBITDA”), “Adjusted Funds from Operations”, "Net Energy Sales", "Net Utility Sales" and "Divisional Operating Profit" are used throughout this MD&A. The terms “Adjusted Net Earnings”, “Adjusted Funds from Operations”, "Adjusted EBITDA", "Net Energy Sales", "Net Utility Sales" and "Divisional Operating Profit" are not recognized measures under U.S. GAAP. There is no standardized measure of “Adjusted Net Earnings”, "Adjusted EBITDA", “Adjusted Funds from Operations”, "Net Energy Sales", "Net Utility Sales", and "Divisional Operating Profit"; consequently, APUC’s method of calculating these measures may differ from methods used by other companies and therefore may not be comparable to similar measures presented by other companies. A calculation and analysis of “Adjusted Net Earnings”, "Adjusted EBITDA", “Adjusted Funds from Operations”, "Net Energy Sales", "Net Utility Sales", and "Divisional Operating Profit" can be found throughout this MD&A.
Adjusted EBITDA
Adjusted EBITDA is a non-GAAP measure used by many investors to compare companies on the basis of ability to generate cash from operations. APUC uses these calculations to monitor the amount of cash generated by APUC as compared to the amount of dividends paid by APUC. APUC uses Adjusted EBITDA to assess the operating performance of APUC without the effects of (as applicable): depreciation and amortization expense, income tax expense or recoveries, acquisition costs, litigation expenses, interest expense, gain or loss on derivative financial instruments, write down of intangibles and property, plant and equipment, earnings attributable to non-controlling interests, non-service pension and post-employment costs, cost related to tax equity financing, gain or loss on foreign exchange, earnings or loss from discontinued operations, changes in value of investments carried at fair value, and other typically non-recurring items. APUC adjusts for these factors as they may be non-cash, unusual in nature and are not factors used by management for evaluating the operating performance of the Company. APUC believes that presentation of this measure will enhance an investor’s understanding of APUC’s operating performance. Adjusted EBITDA is not intended to be representative of cash provided by operating activities or results of operations determined in accordance with U.S. GAAP, and can be impacted positively or negatively by these items.
Adjusted Net Earnings
Adjusted Net Earnings is a non-GAAP measure used by many investors to compare net earnings from operations without the effects of certain volatile primarily non-cash items that generally have no current economic impact or items such as acquisition expenses or litigation expenses that are viewed as not directly related to a company’s operating performance. APUC uses Adjusted Net Earnings to assess its performance without the effects of (as applicable): gains or losses on foreign exchange, foreign exchange forward contracts, interest rate swaps, acquisition costs, one-time costs of arranging tax equity financing, litigation expenses and write down of intangibles and property, plant and equipment, earnings or loss from discontinued operations, unrealized mark-to-market revaluation impacts (other than those realized in connection with the sales of development assets), changes in value of investments carried at fair value, and other typically non-recurring items as these

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

are not reflective of the performance of the underlying business of APUC. The Non-cash accounting charge related to the revaluation of U.S. deferred income tax assets and liabilities as a result of implementation of the effects of the Tax Cuts and Jobs Act ("U.S. Tax Reform") is adjusted as it is also considered a non-recurring item not reflective of the performance of the underlying business of APUC. APUC believes that analysis and presentation of net earnings or loss on this basis will enhance an investor’s understanding of the operating performance of its businesses. Adjusted Net Earnings is not intended to be representative of net earnings or loss determined in accordance with U.S. GAAP, and can be impacted positively or negatively by these items.
Adjusted Funds from Operations
Adjusted Funds from Operations is a non-GAAP measure used by investors to compare cash flows from operating activities without the effects of certain volatile items that generally have no current economic impact or items such as acquisition expenses that are viewed as not directly related to a company’s operating performance. APUC uses Adjusted Funds from Operations to assess its performance without the effects of (as applicable): changes in working capital balances, acquisition expenses, litigation expenses, cash provided by or used in discontinued operations and other typically non-recurring items affecting cash from operations as these are not reflective of the long-term performance of the underlying businesses of APUC. APUC believes that analysis and presentation of funds from operations on this basis will enhance an investor’s understanding of the operating performance of its businesses. Adjusted Funds from Operations is not intended to be representative of cash flows from operating activities as determined in accordance with U.S. GAAP, and can be impacted positively or negatively by these items.
Net Energy Sales
Net Energy Sales is a non-GAAP measure used by investors to identify revenue after commodity costs used to generate revenue where such revenue generally increases or decreases in response to increases or decreases in the cost of the commodity used to produce that revenue. APUC uses Net Energy Sales to assess its revenues without the effects of fluctuating commodity costs as such costs are predominantly passed through either directly or indirectly in the rates that are charged to customers. APUC believes that analysis and presentation of Net Energy Sales on this basis will enhance an investor’s understanding of the revenue generation of its businesses. It is not intended to be representative of revenue as determined in accordance with U.S. GAAP.
Net Utility Sales
Net Utility Sales is a non-GAAP measure used by investors to identify utility revenue after commodity costs, either natural gas or electricity, where these commodity costs are generally included as a pass through in rates to its utility customers. APUC uses Net Utility Sales to assess its utility revenues without the effects of fluctuating commodity costs as such costs are predominantly passed through and paid for by utility customers. APUC believes that analysis and presentation of Net Utility Sales on this basis will enhance an investor’s understanding of the revenue generation of its utility businesses. It is not intended to be representative of revenue as determined in accordance with U.S. GAAP.
Divisional Operating Profit
Divisional Operating Profit is a non-GAAP measure. APUC uses Divisional Operating Profit to assess the operating performance of its business groups without the effects of (as applicable): depreciation and amortization expense, corporate administrative expenses, income tax expense or recoveries, acquisition costs, litigation expenses, interest expense, gain or loss on derivative financial instruments, write down of intangibles and property, plant and equipment, gain or loss on foreign exchange, earnings or loss from discontinued operations, non-service pension and post-employment costs, and other typically non-recurring items. APUC adjusts for these factors as they may be non-cash, unusual in nature and are not factors used by management for evaluating the operating performance of the divisional units. Divisional Operating Profit is calculated inclusive of interest, dividend and equity income earned from indirect investments, and Hypothetical Liquidation at Book Value (“HLBV”) income, which represents the value of net tax attributes earned in the period from electricity generated by certain of its U.S. wind power and U.S. solar generation facilities. APUC believes that presentation of this measure will enhance an investor’s understanding of APUC’s divisional operating performance. Divisional Operating Profit is not intended to be representative of cash provided by operating activities or results of operations determined in accordance with U.S. GAAP.
Capitalized terms used herein and not otherwise defined will have the meanings assigned to them in the Company's most recent AIF.

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

Overview and Business Strategy
APUC is incorporated under the Canada Business Corporations Act. APUC owns and operates a diversified portfolio of regulated and non-regulated generation, distribution, and transmission utility assets which are expected to deliver predictable earnings and cash flows. APUC seeks to maximize total shareholder value through real per share growth in earnings and cash flows to support a growing dividend and share price appreciation. APUC strives to achieve these results while also seeking to maintain a business risk profile consistent with its BBB flat investment grade credit ratings and a strong focus on Environmental, Social and Governance factors.
APUC’s current quarterly dividend to shareholders is $0.1410 per common share or $0.5640 per common share per annum. Based on exchange rates as at February 26, 2020, the quarterly dividend is equivalent to C$0.1876 per common share or C$0.7504 per common share per annum. APUC believes its annual dividend payout allows for both an immediate return on investment for shareholders and retention of sufficient cash within APUC to fund growth opportunities. Changes in the level of dividends paid by APUC are at the discretion of the APUC Board of Directors (the “Board”), with dividend levels being reviewed periodically by the Board in the context of APUC's financial performance and growth prospects.
APUC's operations are organized across two primary business units consisting of: the Regulated Services Group, which primarily owns and operates a portfolio of regulated assets in the United States and Canada, and the Renewable Energy Group, which primarily owns and operates a diversified portfolio of renewable generation assets.
APUC pursues investment opportunities with an objective of maintaining the current business mix between its Regulated Services Group and Renewable Energy Group and with leverage consistent with its current credit ratings 1. The business mix target may from time to time require APUC to grow its Regulated Services Group or implement other strategies in order to pursue investment opportunities within its Renewable Energy Group.
The Company also undertakes development activities for both business units, working with a global reach to identify, develop, acquire, or invest in renewable power generating facilities, regulated utilities and other complementary infrastructure projects. See additional discussion in Corporate Development Activities.
Summary Organizational Structure
The following represents a summarized organizational chart for APUC. A more detailed description of APUC's organizational structure can be found in the most recent AIF.

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

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

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

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

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

(all dollar amounts in $ millions except per share information) | Three Months Ended December 31 |  | Twelve Months Ended December 31
2019 |  | 2018 |  | Change |  | 2019 |  | 2018 |  | Change
Net earnings attributable to shareholders | $172.1 |  | $44.0 |  | 291% |  | $530.9 |  | $185.0 |  | 187%
Adjusted Net Earnings 1 | $103.6 |  | $70.5 |  | 47% |  | $321.3 |  | $312.2 |  | 3%
Adjusted EBITDA 1 | $231.5 |  | $198.9 |  | 16% |  | $838.6 |  | $804.4 |  | 4%
Net earnings per common share | $0.34 |  | $0.09 |  | 278% |  | $1.05 |  | $0.38 |  | 176%
Adjusted Net Earnings per common share 1 | $0.20 |  | $0.14 |  | 43% |  | $0.63 |  | $0.66 |  | (5)%

1 | See Non-GAAP Financial Measures.

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

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

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

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

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

Algonquin Power & Utilities Corp. - Management Discussion & Analysis | 8

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

Key Financial Information | Three Months Ended December 31
(all dollar amounts in $ millions except per share information) | 2019 |  | 2018
Revenue | $ | 439.7 |  |  | $ | 421.9 |
Net earnings attributable to shareholders | 172.1 |  |  | 44.0 |
Cash provided by operating activities | 167.5 |  |  | 168.6 |
Adjusted Net Earnings 1 | 103.6 |  |  | 70.5 |
Adjusted EBITDA 1 | 231.5 |  |  | 198.9 |
Adjusted Funds from Operations 1 | 144.1 |  |  | 132.5 |
Dividends declared to common shareholders | 74.3 |  |  | 63.1 |
Weighted average number of common shares outstanding | 519,846,220 |  |  | 477,450,181 |
Per share |  |  |
Basic net earnings | $ | 0.34 |  |  | $ | 0.09 |
Diluted net earnings | $ | 0.33 |  |  | $ | 0.09 |
Adjusted Net Earnings 1,2 | $ | 0.20 |  |  | $ | 0.14 |
Dividends declared to common shareholders | $ | 0.14 |  |  | $ | 0.13 |

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

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

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

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

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

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

During the three months ended December 31, 2019, cash provided by operating activities totaled $167.5 million as compared to $168.6 million during the same period in 2018. During the three months ended December 31, 2019, Adjusted Funds from Operations totaled $144.1 million as compared to Adjusted Funds from Operations of $132.5 million during the same period in 2018 (see Non-GAAP Financial Measures).
During the three months ended December 31, 2019, Adjusted EBITDA totaled $231.5 million as compared to $198.9 million during the same period in 2018, an increase of $32.6 million or 16.4%. A more detailed analysis of these factors is presented within the reconciliation of Adjusted EBITDA to net earnings set out below (see Non-GAAP Financial Measures).
2019 Annual Results From Operations

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

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

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

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

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

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

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

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

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

2019 Adjusted EBITDA Summary
Adjusted EBITDA (see Non-GAAP Financial Measures) for the three months ended December 31, 2019 totaled $231.5 million as compared to $198.9 million during the same period in 2018, an increase of $32.6 million or 16.4%. Adjusted EBITDA for the twelve months ended December 31, 2019 totaled $838.6 million as compared to $804.4 million during the same period in 2018, an increase of $34.2 million or 4.3%. In the first quarter of 2018, APUC recorded a one-time acceleration of HLBV income of $55.9 million. Excluding this adjustment, Adjusted EBITDA increased by $90.1 million year over year. The breakdown of Adjusted EBITDA by the Company's main operating segments and a summary of changes are shown below.

Adjusted EBITDA by business units | Three Months Ended December 31 |  | Twelve Months Ended December 31
(all dollar amounts in $ millions) | 2019 |  | 2018 |  | 2019 |  | 2018
Regulated Services Group Operating Profit | $ | 160.5 |  |  | $ | 135.0 |  |  | $ | 565.4 |  |  | $ | 551.6 |
Renewable Energy Group Operating Profit | 85.9 |  |  | 78.7 |  |  | 328.5 |  |  | 303.6 |
Administrative Expenses | (15.2 | ) |  | (15.0 | ) |  | (56.8 | ) |  | (52.7 | )
Other Income & Expenses | 0.3 |  |  | 0.2 |  |  | 1.5 |  |  | 1.9 |
Total APUC Adjusted EBITDA | $ | 231.5 |  |  | $ | 198.9 |  |  | $ | 838.6 |  |  | $ | 804.4 |
Change in Adjusted EBITDA ($) | $ | 32.6 |  |  |  |  | $ | 34.2 |  |  |
Change in Adjusted EBITDA (%) | 16.4 | % |  |  |  | 4.3 | % |  |

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

2019 Regulated Services Group Operating Results

| Three Months Ended December 31 |  | Twelve Months Ended December 31
| 2019 |  | 2018 |  | 2019 |  | 2018
Revenue |  |  |  |  |  |  |
Utility electricity sales and distribution | $ | 181.9 |  |  | $ | 193.2 |  |  | $ | 784.4 |  |  | $ | 831.2 |
Less: cost of sales – electricity | (59.2 | ) |  | (63.4 | ) |  | (247.4 | ) |  | (265.1 | )
Net Utility Sales - electricity 1 | 122.7 |  |  | 129.8 |  |  | 537.0 |  |  | 566.1 |
Utility natural gas sales and distribution | 132.3 |  |  | 117.5 |  |  | 402.6 |  |  | 396.6 |
Less: cost of sales – natural gas | (58.9 | ) |  | (59.0 | ) |  | (170.5 | ) |  | (183.0 | )
Net Utility Sales - natural gas 1 | 73.4 |  |  | 58.5 |  |  | 232.1 |  |  | 213.6 |
Utility water distribution & wastewater treatment sales and distribution | 32.0 |  |  | 30.4 |  |  | 130.5 |  |  | 128.4 |
Less: cost of sales – water | (2.2 | ) |  | (2.1 | ) |  | (8.1 | ) |  | (8.8 | )
Net Utility Sales - water distribution & wastewater treatment 1 | 29.8 |  |  | 28.3 |  |  | 122.4 |  |  | 119.6 |
Gas transportation | 11.4 |  |  | 10.4 |  |  | 35.1 |  |  | 33.4 |
Other revenue | 7.7 |  |  | 4.9 |  |  | 14.3 |  |  | 11.6 |
Net Utility Sales 1 | 245.0 |  |  | 231.9 |  |  | 940.9 |  |  | 944.3 |
Operating expenses | (96.0 | ) |  | (99.0 | ) |  | (396.6 | ) |  | (401.5 | )
Other income | 10.2 |  |  | 1.5 |  |  | 15.3 |  |  | 5.6 |
HLBV 2 | 1.3 |  |  | 0.6 |  |  | 5.8 |  |  | 3.2 |
Divisional Operating Profit 1,3 | $ | 160.5 |  |  | $ | 135.0 |  |  | $ | 565.4 |  |  | $ | 551.6 |

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

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

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

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

1 | See Non-GAAP Financial Measures.

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

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

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

1 | See Non-GAAP Financial Measures.

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

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

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

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

RENEWABLE ENERGY GROUP

2019 Electricity Generation Performance
| Long Term Average Resource |  | Three Months Ended December 31 |  | Long Term Average Resource |  | Twelve Months Ended December 31
(Performance in GW-hrs sold) |  | 2019 |  | 2018 |  |  | 2019 |  | 2018
Hydro Facilities: |  |  |  |  |  |  |  |  |  |  |
Maritime Region | 37.6 |  |  | 35.8 |  |  | 31.4 |  |  | 148.2 |  |  | 132.7 |  |  | 107.5 |
Quebec Region | 72.6 |  |  | 72.7 |  |  | 73.6 |  |  | 273.3 |  |  | 270.8 |  |  | 263.7 |
Ontario Region | 26.2 |  |  | 22.2 |  |  | 31.3 |  |  | 120.4 |  |  | 103.4 |  |  | 106.5 |
Western Region | 12.6 |  |  | 13.3 |  |  | 11.2 |  |  | 65.0 |  |  | 65.5 |  |  | 59.8 |
| 149.0 |  |  | 144.0 |  |  | 147.5 |  |  | 606.9 |  |  | 572.4 |  |  | 537.5 |
Wind Facilities: |  |  |  |  |  |  |  |  |  |  |
St. Damase | 22.7 |  |  | 20.5 |  |  | 22.2 |  |  | 76.9 |  |  | 76.7 |  |  | 78.8 |
St. Leon | 121.4 |  |  | 112.4 |  |  | 101.4 |  |  | 430.2 |  |  | 404.0 |  |  | 394.8 |
Red Lily 1 | 24.1 |  |  | 23.4 |  |  | 20.0 |  |  | 88.5 |  |  | 81.8 |  |  | 81.3 |
Morse | 30.5 |  |  | 25.9 |  |  | 26.2 |  |  | 108.8 |  |  | 96.4 |  |  | 96.8 |
Amherst 2 | 67.9 |  |  | 67.0 |  |  | 58.7 |  |  | 229.8 |  |  | 223.4 |  |  | 105.7 |
Sandy Ridge | 43.6 |  |  | 31.9 |  |  | 43.8 |  |  | 158.3 |  |  | 126.5 |  |  | 152.2 |
Minonk | 189.8 |  |  | 193.7 |  |  | 173.8 |  |  | 673.7 |  |  | 654.6 |  |  | 611.3 |
Senate | 140.0 |  |  | 131.1 |  |  | 125.2 |  |  | 520.4 |  |  | 506.0 |  |  | 484.9 |
Shady Oaks | 100.5 |  |  | 97.7 |  |  | 91.5 |  |  | 355.6 |  |  | 345.8 |  |  | 326.6 |
Odell | 238.0 |  |  | 224.9 |  |  | 199.9 |  |  | 831.8 |  |  | 748.1 |  |  | 759.4 |
Deerfield | 167.9 |  |  | 163.9 |  |  | 153.8 |  |  | 546.0 |  |  | 522.6 |  |  | 531.2 |
| 1,146.4 |  |  | 1,092.4 |  |  | 1,016.5 |  |  | 4,020.0 |  |  | 3,785.9 |  |  | 3,623.0 |
Solar Facilities: |  |  |  |  |  |  |  |  |  |  |  |  |  |
Cornwall | 2.2 |  |  | 1.8 |  |  | 1.8 |  |  | 14.7 |  |  | 15.0 |  |  | 14.5 |
Bakersfield | 13.0 |  |  | 12.2 |  |  | 9.5 |  |  | 77.2 |  |  | 68.6 |  |  | 70.0 |
Great Bay Solar 3 | 25.7 |  |  | 24.2 |  |  | 26.4 |  |  | 138.5 |  |  | 134.2 |  |  | 110.6 |
| 40.9 |  |  | 38.2 |  |  | 37.7 |  |  | 230.4 |  |  | 217.8 |  |  | 195.1 |
Renewable Energy Performance | 1,336.3 |  |  | 1,274.6 |  |  | 1,201.7 |  |  | 4,857.3 |  |  | 4,576.1 |  |  | 4,355.6 |
Thermal Facilities: |  |  |  |  |  |  |  |  |  |  |  |  |  |
Windsor Locks | N/A 4 |  |  | 28.0 |  |  | 46.1 |  |  | N/A 4 |  |  | 115.3 |  |  | 154.7 |
Sanger | N/A 4 |  |  | 17.8 |  |  | 11.3 |  |  | N/A 4 |  |  | 57.6 |  |  | 146.4 |
|  |  |  | 45.8 |  |  | 57.4 |  |  |  |  |  | 172.9 |  |  | 301.1 |
Total Performance |  |  |  | 1,320.4 |  |  | 1,259.1 |  |  |  |  |  | 4,749.0 |  |  | 4,656.7 |

1 | APUC owns a 75% equity interest in the Red Lily Wind Facility but accounts for the facility using the equity method. The production figures represent full energy produced by the facility.
2 | APUC owns a majority interest in the Amherst Island Wind Facility. The production figures represent full energy produced by the facility. The Amherst Island Wind Facility achieved COD on June 15, 2018 in accordance with the terms of the Power Purchase Agreement ("PPA"), however, the facility was partially operational prior to that date. The twelve months ended December 31, 2018 production data includes all energy produced during the year.
3 | The Great Bay Solar Facility achieved COD on March 29, 2018 in accordance with the terms of the PPA, however, the facility was partially operational prior to that date. The twelve months ended December 31, 2018 production data includes all energy produced during the year.
4 | Natural gas fired co-generation facility.

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

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

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

2019 Renewable Energy Group Operating Results
| Three Months Ended December 31 |  | Twelve Months Ended December 31
(all dollar amounts in $ millions) | 2019 |  | 2018 |  | 2019 |  | 2018
Revenue 1 |  |  |  |  |  |  |
Hydro | $ | 10.4 |  |  | $ | 11.7 |  |  | $ | 41.7 |  |  | $ | 42.6 |
Wind | 49.4 |  |  | 37.7 |  |  | 153.3 |  |  | 133.5 |
Solar | 2.8 |  |  | 2.8 |  |  | 18.6 |  |  | 17.2 |
Thermal | 8.1 |  |  | 10.2 |  |  | 32.9 |  |  | 42.1 |
Total Revenue | $ | 70.7 |  |  | $ | 62.4 |  |  | $ | 246.5 |  |  | $ | 235.4 |
Less: |  |  |  |  |  |  |
Cost of Sales - Energy 2 | (0.9 | ) |  | (1.4 | ) |  | (4.3 | ) |  | (5.5 | )
Cost of Sales - Thermal | (3.2 | ) |  | (5.1 | ) |  | (13.0 | ) |  | (21.7 | )
Realized gain/(loss) on hedges 3 | — |  |  | 0.1 |  |  | (0.2 | ) |  | 0.1 |
Net Energy Sales 8 | $ | 66.6 |  |  | $ | 56.0 |  |  | $ | 229.0 |  |  | $ | 208.3 |
Renewable Energy Credits 4 | 2.8 |  |  | 2.7 |  |  | 10.1 |  |  | 11.0 |
Other Revenue | 0.8 |  |  | 0.4 |  |  | 1.4 |  |  | 0.9 |
Total Net Revenue | $ | 70.2 |  |  | $ | 59.1 |  |  | $ | 240.5 |  |  | $ | 220.2 |
Expenses & Other Income |  |  |  |  |  |  |
Operating expenses | (19.2 | ) |  | (13.2 | ) |  | (75.2 | ) |  | (71.0 | )
Dividend, interest, equity and other income 5 | 20.2 |  |  | 18.3 |  |  | 104.0 |  |  | 45.7 |
HLBV income 8 | 14.7 |  |  | 14.5 |  |  | 59.2 |  |  | 108.7 |
Divisional Operating Profit 6,7 | $ | 85.9 |  |  | $ | 78.7 |  |  | $ | 328.5 |  |  | $ | 303.6 |

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

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

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

2019 Fourth Quarter Operating Results
For the three months ended December 31, 2019, the Renewable Energy Group's facilities generated $85.9 million of operating profit as compared to $78.7 million during the same period in 2018, which represents an increase of $7.2 million or 9.1%, excluding corporate administration expenses.
Highlights of the changes are summarized in the following table:

(all dollar amounts in $ millions) | Three Months Ended December 31
Prior Period Operating Profit | $ | 78.7 |
Existing Facilities |
Hydro: Decrease is primarily due to lower production in the Ontario and Quebec Regions, partially offset by additional REC revenue and lower operating expenses. | (0.2 | )
Wind Canada: Increase is primarily due to higher production at the St. Leon Wind Facility, partially offset by higher operating expenses. | 0.9 |
Wind U.S.: Increase is primarily due to higher overall production as well as lower operating expenses. | 2.4 |
Solar Canada | — |
Solar U.S.: Decrease due to lower production at the Great Bay Solar Facility partially offset by favorable REC pricing, higher HLBV income and higher production at the Bakersfield Solar Facility. | (0.2 | )
Thermal: Increase is primarily due to lower cost of fuel at the Sanger Thermal Facility as well additional REC revenue, partially offset by lower production at the Windsor Locks Thermal Facility. | 0.4 |
Other: Decrease is due to higher expenses related to early stage development projects. | (1.7 | )
| 1.6 |
New Facilities and Investments |
Wind Canada: The Amherst Island Wind Facility was previously accounted for as an equity investment. | 4.5 |
Atlantica & AAGES: Dividends from Atlantica 1, net of AAGES equity loss. | 1.0 |
| 5.5 |
Foreign Exchange | 0.1 |
Current Period Divisional Operating Profit 2 | $ | 85.9 |

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

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

2019 Annual Operating Results
For the twelve months ended December 31, 2019, the Renewable Energy Group's facilities generated $328.5 million of operating profit as compared to $303.6 million during the same period in 2018, which represents an increase of $24.9 million or 8.2%, excluding corporate administration expenses.
Highlights of the changes are summarized in the following table:

(all dollar amounts in $ millions) | Twelve Months Ended December 31
Prior Period Operating Profit | $ | 303.6 |
Existing Facilities |
Hydro: Increase is primarily due to higher production and additional REC sales, partially offset by higher operating expenses. | 0.8 |
Wind Canada: Increase is primarily due to annual rate increases and higher production at the St. Leon Wind Facility, partially offset by higher operating costs. | 1.6 |
Wind U.S.: Decrease is primarily due to HLBV income acceleration ($54.9 million) resulting from U.S. Tax Reform recognized in the prior year, lower market pricing at the Senate Wind Facility and lower REC rates at the Minonk Wind Facility, partially offset by higher overall production. | (54.2 | )
Solar Canada: Decrease is primarily due to higher operating expenses offset by higher production. | (0.1 | )
Solar U.S.: Decrease is primarily due to HLBV income acceleration ($1.0 million) resulting from U.S. Tax Reform that was recognized in the prior year. | (1.0 | )
Thermal: Increase is primarily due to lower operating costs, lower cost of fuel and higher REC revenue, partially offset by lower overall production. | 0.7 |
Other: Increase is due to lower expenses related to early stage development projects. | 3.1 |
| (49.1 | )
New Facilities and Investments |
Wind Canada: Amherst Island Wind Facility achieved COD in June 2018. | 15.9 |
Solar U.S.: Great Bay Solar Facility achieved full COD in March 2018. | 6.4 |
Atlantica and AAGES: Dividends from Atlantica 1 net of AAGES equity loss. | 53.0 |
| 75.3 |
Foreign Exchange | (1.3 | )
Current Period Divisional Operating Profit 2 | $ | 328.5 |

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

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

APUC: CORPORATE AND OTHER EXPENSES

| Three Months Ended December 31 |  | Twelve Months Ended December 31
(all dollar amounts in $ millions) | 2019 |  | 2018 |  | 2019 |  | 2018
Corporate and other expenses: |  |  |  |  |  |  |
Administrative expenses | $ | 15.2 |  |  | $ | 15.0 |  |  | $ | 56.8 |  |  | $ | 52.7 |
Loss (gain) on foreign exchange | 3.1 |  |  | 0.7 |  |  | 3.1 |  |  | (0.1 | )
Interest expense | 47.4 |  |  | 40.3 |  |  | 181.5 |  |  | 152.1 |
Depreciation and amortization | 77.7 |  |  | 63.8 |  |  | 284.3 |  |  | 260.8 |
Change in value of investments carried at fair value | (98.1 | ) |  | 46.0 |  |  | (278.1 | ) |  | 138.0 |
Interest, dividend, equity, and other (income) loss 1 | (0.4 | ) |  | (0.4 | ) |  | (1.6 | ) |  | (1.8 | )
Pension and post-employment non-service costs | 8.4 |  |  | 3.4 |  |  | 17.3 |  |  | 5.0 |
Other losses | 6.2 |  |  | 2.3 |  |  | 15.1 |  |  | 2.7 |
Acquisition-related costs, net | 6.4 |  |  | (8.9 | ) |  | 11.6 |  |  | 0.7 |
Loss (gain) on derivative financial instruments | (0.5 | ) |  | (0.3 | ) |  | (16.1 | ) |  | 0.6 |
Income tax expense | 12.5 |  |  | 2.8 |  |  | 70.1 |  |  | 53.4 |

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

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

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

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

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

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

| Three Months Ended December 31 |  | Twelve Months Ended December 31
(all dollar amounts in $ millions) | 2019 |  | 2018 |  | 2019 |  | 2018
Net earnings attributable to shareholders | $ | 172.1 |  |  | $ | 44.0 |  |  | $ | 530.9 |  |  | $ | 185.0 |
Add (deduct): |  |  |  |  |  |  |
Net earnings attributable to the non-controlling interest, exclusive of HLBV 1 | (3.7 | ) |  | 3.4 |  |  | 19.1 |  |  | 4.8 |
Income tax expense | 12.5 |  |  | 2.8 |  |  | 70.1 |  |  | 53.4 |
Interest expense on long-term debt and others | 47.4 |  |  | 40.3 |  |  | 181.5 |  |  | 152.1 |
Other losses | 6.2 |  |  | 2.3 |  |  | 15.1 |  |  | 2.7 |
Acquisition-related costs | 6.4 |  |  | (8.9 | ) |  | 11.6 |  |  | 0.7 |
Pension and post-employment non-service costs | 8.4 |  |  | 3.4 |  |  | 17.3 |  |  | 5.0 |
Change in value of investments carried at fair value 2 | (98.1 | ) |  | 46.0 |  |  | (278.1 | ) |  | 138.0 |
Costs related to tax equity financing | — |  |  | 1.3 |  |  | — |  |  | 1.3 |
Loss (gain) on derivative financial instruments | (0.5 | ) |  | (0.3 | ) |  | (16.1 | ) |  | 0.6 |
Realized (loss) gain on energy derivative contracts | — |  |  | 0.1 |  |  | (0.2 | ) |  | 0.1 |
Loss (gain) on foreign exchange | 3.1 |  |  | 0.7 |  |  | 3.1 |  |  | (0.1 | )
Depreciation and amortization | 77.7 |  |  | 63.8 |  |  | 284.3 |  |  | 260.8 |
Adjusted EBITDA | $ | 231.5 |  |  | $ | 198.9 |  |  | $ | 838.6 |  |  | $ | 804.4 |

1 |  | HLBV represents the value of net tax attributes earned during the period primarily from electricity generated by certain U.S. wind power and U.S. solar generation facilities. HLBV earned in the three and twelve months ended December 31, 2019 amounted to $16.0 million and $65.0 million as compared to $13.8 million and $110.7 million during the same period in 2018. In the first quarter of 2018 a one-time acceleration of HLBV income in the amount of $55.9 million was recorded as a result of U.S. Tax Reform. Excluding the one-time acceleration of HLBV due to U.S. Tax Reform, Adjusted EBITDA increased by $90.1 million year over year.
2 |  | See Note 8 in the annual audited consolidated financial statements

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

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

| Three Months Ended December 31 |  | Twelve Months Ended December 31
(all dollar amounts in $ millions except per share information) | 2019 |  | 2018 |  | 2019 |  | 2018
Net earnings attributable to shareholders | $ | 172.1 |  |  | $ | 44.0 |  |  | $ | 530.9 |  |  | $ | 185.0 |
Add (deduct): |  |  |  |  |  |  |
Loss (gain) on derivative financial instruments 1 | (0.5 | ) |  | (0.3 | ) |  | (0.3 | ) |  | 0.6 |
Realized (loss) gain on energy derivative contracts | — |  |  | 0.1 |  |  | (0.2 | ) |  | 0.1 |
Other losses | 6.1 |  |  | 1.9 |  |  | 15.1 |  |  | 0.8 |
Loss (gain) on foreign exchange | 3.0 |  |  | 0.7 |  |  | 3.1 |  |  | (0.1 | )
Acquisition-related costs | 6.4 |  |  | (8.9 | ) |  | 11.6 |  |  | 0.7 |
Change in value of investments carried at fair value 3 | (98.1 | ) |  | 46.0 |  |  | (278.1 | ) |  | 138.0 |
Costs related to tax equity financing | — |  |  | 1.3 |  |  | — |  |  | 1.3 |
Other non-recurring adjustments | 2.2 |  |  | — |  |  | 2.2 |  |  | — |
U.S. Tax Reform and related deferred tax adjustments 2 | — |  |  | (18.4 | ) |  | — |  |  | (18.4 | )
Adjustment for taxes related to above | 12.4 |  |  | 4.1 |  |  | 37.0 |  |  | 4.2 |
Adjusted Net Earnings | $ | 103.6 |  |  | $ | 70.5 |  |  | $ | 321.3 |  |  | $ | 312.2 |
Adjusted Net Earnings per share | $ | 0.20 |  |  | $ | 0.14 |  |  | $ | 0.63 |  |  | $ | 0.66 |

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

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

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

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

| Three Months Ended December 31 |  | Twelve Months Ended December 31
(all dollar amounts in $ millions) | 2019 |  | 2018 |  | 2019 |  | 2018
Cash flows from operating activities | $ | 167.5 |  |  | $ | 168.6 |  |  | $ | 611.3 |  |  | $ | 530.4 |
Add (deduct): |  |  |  |  |  |  |
Changes in non-cash operating items | (29.8 | ) |  | (27.3 | ) |  | (60.3 | ) |  | 8.1 |
Production based cash contributions from non-controlling interests | — |  |  | — |  |  | 3.6 |  |  | 13.9 |
Acquisition-related costs | 6.4 |  |  | (8.8 | ) |  | 11.6 |  |  | 0.7 |
Reimbursement of operating expenses incurred on joint venture | — |  |  | — |  |  | — |  |  | 1.0 |
Adjusted Funds from Operations | $ | 144.1 |  |  | $ | 132.5 |  |  | $ | 566.2 |  |  | $ | 554.1 |

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

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

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

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

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

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

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

SUMMARY OF PROPERTY, PLANT, AND EQUIPMENT EXPENDITURES

| Three Months Ended December 31 |  | Twelve Months Ended December 31
(all dollar amounts in $ millions) | 2019 |  | 2018 |  | 2019 |  | 2018
Regulated Services Group |  |  |  |  |  |  |
Rate Base Maintenance | $ | 51.9 |  |  | $ | 41.5 |  |  | $ | 194.5 |  |  | $ | 177.7 |
Rate Base Growth | 185.1 |  |  | 76.0 |  |  | 373.5 |  |  | 173.9 |
Property, Plant & Equipment Acquired 1 | 186.2 |  |  | — |  |  | 186.6 |  |  | — |
| $ | 423.2 |  |  | $ | 117.5 |  |  | $ | 754.6 |  |  | $ | 351.6 |
Renewable Energy Group |  |  |  |  |  |  |
Maintenance | $ | 12.5 |  |  | $ | 12.6 |  |  | $ | 37.3 |  |  | $ | 27.4 |
Investment in Capital Projects 2 | (47.1 | ) |  | (18.0 | ) |  | 425.8 |  |  | 71.6 |
International Investments 3 | 28.0 |  |  | 345.0 |  |  | 122.2 |  |  | 957.6 |
| $ | (6.6 | ) |  | $ | 339.6 |  |  | $ | 585.3 |  |  | $ | 1,056.6 |
Total Capital Expenditures | $ | 416.6 |  |  | $ | 457.1 |  |  | $ | 1,339.9 |  |  | $ | 1,408.2 |

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

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

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

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

1 | Includes international investments in utilities.

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

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

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

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

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

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

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

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

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

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

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

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

Equity
The common shares of APUC are publicly traded on the Toronto Stock Exchange (“TSX”) and the New York Stock Exchange ("NYSE") under the trading symbol "AQN". As at February 26, 2020, APUC had 525,624,407 issued and outstanding common shares.
APUC may issue an unlimited number of common shares. The holders of common shares are entitled to dividends, if and when declared; to one vote for each share at meetings of the holders of common shares; and to receive a pro rata share of any remaining property and assets of APUC upon liquidation, dissolution or winding up of APUC. All shares are of the same class and with equal rights and privileges and are not subject to future calls or assessments.
APUC is also authorized to issue an unlimited number of preferred shares, issuable in one or more series, containing terms and conditions as approved by the Board. As at December 31, 2019, APUC had outstanding:

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

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

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

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

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

As at December 31, 2019, total unrecognized compensation costs related to non-vested options and share unit awards were $1.3 million and $12.8 million, respectively, and are expected to be recognized over a period of 1.68 and 1.86 years, respectively.
Stock Option Plan
APUC has a stock option plan that permits the grant of share options to key officers, directors, employees and selected service providers. Except in certain circumstances, the term of an option shall not exceed ten (10) years from the date of the grant of the option.
APUC determines the fair value of options granted using the Black-Scholes option-pricing model. The estimated fair value of options, including the effect of estimated forfeitures, is recognized as an expense on a straight-line basis over the options’ vesting periods while ensuring that the cumulative amount of compensation cost recognized at least equals the value of the vested portion of the award at that date. During the twelve months ended December 31, 2019, the Company granted 1,113,775 options to executives of the Company. The options allow for the purchase of common shares at a weighted average price of C$14.96, the market price of the underlying common share at the date of grant. During the year, executives of the Company exercised 841,288 stock options at a weighted average exercise price of C$11.23 in exchange for common shares issued from treasury and 3,041,217 options were settled at their cash value as payment for the exercise price and tax withholdings related to the exercise of the options.
As at December 31, 2019, a total of 3,523,912 options were issued and outstanding under the stock option plan.
Performance Share Units
APUC issues performance share units (“PSUs”) and restricted share units ("RSUs") to certain members of management as part of APUC’s long-term incentive program. During the twelve months ended December 31, 2019, the Company granted (including dividends and performance adjustments) 1,471,442 PSUs and RSUs to executives and employees of the Company. During the year, the Company settled 344,340 PSUs, of which 142,473 PSUs were exchanged for common shares issued from treasury and 143,078 PSUs were settled at their cash value as payment for tax withholdings related to the settlement of the PSUs. Additionally, during 2019, a total of 107,191 PSUs were forfeited.
As at December 31, 2019, a total of 2,412,043 PSUs and RSUs were granted and outstanding under the PSU and RSU plans.
Directors' Deferred Share Units
APUC has a Directors' Deferred Share Unit Plan. Under the plan, non-employee directors of APUC receive all or any portion of their annual compensation in deferred share units (“DSUs”) and may elect to receive any portion of their remaining compensation in DSUs. The DSUs provide for settlement in cash or shares at the election of APUC. As APUC does not expect to settle the DSUs in cash, these DSUs are accounted for as equity awards. During the twelve months ended December 31, 2019, the Company issued 79,762 DSUs (including DSUs in lieu of dividends) to the directors of the Company.
As at December 31, 2019, a total of 460,418 DSUs had been granted under the DSU plan.
Bonus Deferral Restricted Share Units
The Company has a bonus deferral restricted share units ("RSUs") program that is available to certain employees. The eligible employees have the option to receive a portion or all of their annual bonus payment in RSUs in lieu of cash. The RSUs provide for settlement in shares, and therefore these options are accounted for as equity awards. During the twelve months ended December 31, 2019, 262,390 RSUs were issued (including RSUs in lieu of dividends) to employees of the Company.
Employee Share Purchase Plan
APUC has an Employee Share Purchase Plan (the “ESPP”) which allows eligible employees to use a portion of their earnings to purchase common shares of APUC. The aggregate number of shares reserved for issuance from treasury by APUC under this plan shall not exceed 2,000,000 shares. During the twelve months ended December 31, 2019, the Company issued 253,538 common shares to employees under the ESPP.
As at December 31, 2019, a total of 1,285,789 shares had been issued under the ESPP.

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

MANAGEMENT OF CAPITAL STRUCTURE
APUC views its capital structure in terms of its debt and equity levels at its individual operating groups and at an overall company level.
APUC’s objectives when managing capital are:

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

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

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

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

• | To maintain sufficient liquidity to ensure sustainable dividends made to shareholders; and

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

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

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

Long Sault Hydro Facility
Effective December 31, 2013, APUC acquired the shares of Algonquin Power Corporation Inc. (“APC”) which was partially owned by Senior Executives. APC owns the partnership interest in the 18 MW Long Sault Hydro Facility. A final post-closing adjustment related to the transaction remains outstanding.
The above related party transactions have been recorded at the exchange amounts agreed to by the parties to the transactions.
ENTERPRISE RISK MANAGEMENT
The Corporation is subject to a number of risks and uncertainties, certain of which are described below. A risk is the possibility that an event might happen in the future that could have a negative effect on the financial condition, financial performance or business of the Corporation. The actual effect of any event on the Corporation’s business could be materially different from what is anticipated or described below. The description of risks below does not include all possible risks.
Led by the Chief Compliance and Risk Officer, the Corporation has an established enterprise risk management, or ("ERM"), framework. The Corporation’s ERM framework follows the guidance of ISO 31000 and the Committee of Sponsoring Organizations of the Treadway Commission ("COSO") Enterprise Risk Management - Integrated Framework. The Corporation’s ERM framework is intended to systematically identify, assess, and mitigate the key strategic, operational, financial, and compliance risks that may impact the achievement of the Corporation’s current objectives, as well as those inherent to strategic alternatives available to the Corporation. The Corporation’s Board-approved ERM policy details the Corporation’s risk management processes, risk appetite, and risk governance structure.
As part of the risk management process, risk registers have been developed across the organization through ongoing risk identification and risk assessment exercises facilitated by the Corporation’s internal ERM team. Key risks and associated mitigation strategies are reviewed by the executive-level Enterprise Risk Management Council and are presented to the Board’s Risk Committee periodically.
Risks are evaluated consistently across the Corporation using a standardized risk scoring matrix to assess impact and likelihood. Financial, reputational and safety implications are among those considered when determining the impact of a potential risk. Risk treatment priorities are established based upon these risk assessments and incorporated into the development of the Corporation’s strategic and business plans.
The risks discussed below are not intended as a complete list of all exposures that APUC is encountering or may encounter. A further assessment of APUC and its subsidiaries’ risk factors are set out in the Company's most recent AIF available on SEDAR and EDGAR. The risks discussed below are intended to provide an update on those that were previously disclosed.
Treasury Risk Management
Downgrade in the Company's Credit Rating Risk
APUC has a long term consolidated corporate credit rating of BBB from S&P, a BBB rating from DBRS and a BBB issuer rating from Fitch. Liberty Power, the parent company for the U.S. and Canadian generating assets under the Renewable Energy Group, has a BBB issuer rating from S&P, BBB issuer rating from DBRS and a BBB issuer rating from Fitch. LUCo, the parent company for the U.S. regulated utilities under the Regulated Services Group, has a corporate credit rating of BBB from S&P and a BBB issuer rating from Fitch. Debt issued by Liberty Finance, a special purpose financing entity of LUCo, has a rating of BBB (high) from DBRS and BBB+ from Fitch. Empire has a BBB issuer rating from S&P and a Baa1 issuer rating from Moody's. Liberty Utilities (Canada) LP, the parent company for the Canadian regulated utilities under the Regulated Services Group has an issuer rating of BBB from DBRS.
The ratings indicate the agencies’ assessment of the ability to pay the interest and principal of debt securities issued by such entities. A rating is not a recommendation to purchase, sell or hold securities and each rating should be evaluated independently of any other rating. The lower the rating, the higher the interest cost of the securities when they are sold. A downgrade in APUC’s or its subsidiaries' issuer corporate credit ratings would result in an increase in APUC’s borrowing costs under its bank credit facilities and future long-term debt securities issued. Any such downgrade could also adversely impact the market price of the outstanding securities of the Company, could impact the Company's ability to acquire additional regulated utilities and could require the Company to post additional collateral security under some of its contracts and hedging arrangements. If any of APUC’s ratings fall below investment grade (investment grade is defined as BBB- or above for S&P and Fitch, BBB (low) or above for DBRS and Baa3 or above for Moody's), APUC’s ability to issue short-term debt or other securities or to market those securities would be constrained or made more difficult or expensive. Therefore, any such downgrades could have a material adverse effect on APUC’s business, cost of capital, financial condition and results of operations.
The Company is not adopting or endorsing such ratings, and such ratings do not indicate APUC’s assessment of its own ability to pay the interest or principal of debt securities it issues. The Company is providing such ratings only to assist with the assessment of future risks and effects of ratings on the Company’s financing costs.

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

No assurances can be provided that any of APUC's current ratings will remain in effect for any given period of time or that a rating will not be lowered or withdrawn entirely by a rating agency if, in its judgment, circumstances in the future so warrant. Each rating agency employs proprietary scoring methodologies that assess business and financial risks of the entity rated. There can be no assurance that the principles of the rating remain consistently applied, and these principles are subject to change from time to time at each rating agency’s discretion. For example, a rating agency’s views on total allowable leverage, specific industry risk factors, country risk and the company’s business mix, amongst other factors, may change. Such changes could require APUC to adjust its business and strategy in order to maintain its credit ratings. APUC currently anticipates that to continue to maintain a BBB flat investment grade credit ratings, it will, amongst other things, need to execute its growth strategy in a manner that preserves satisfaction of financial leverage targets and continues to generate no less than approximately its current portion of EBITDA (as determined by applicable rating agency methodologies) from APUC’s Regulated Services Group. There can be no assurance that APUC will be successful, and the failure to do so could have a negative impact on APUC’s credit ratings. The business mix target may from time to time require APUC to grow its Regulated Services Group or implement other strategies in order to pursue investment opportunities within its Renewable Energy Group.
Capital Markets and Liquidity Risk
As at December 31, 2019, the Company had approximately $3,932.2 million of long-term consolidated indebtedness. Management of the Company believes, based on its current expectations as to the Company’s future performance, that the cash flow from its operations and funds available to it under its revolving credit facilities and its ability to access capital markets will be adequate to enable the Company to finance its operations, execute its business strategy and maintain an adequate level of liquidity. However, expected revenue and capital expenditures are only estimates. Moreover, actual cash flows from operations are dependent on regulatory, market and other conditions that are beyond the control of the Company. As such, no assurance can be given that management’s expectations as to future performance will be realized.
The ability of the Company to raise additional debt or equity or to do so on favourable terms may be adversely affected by adverse financial and operational performance, or by financial market disruptions or other factors outside the control of the Company.
In addition, the Company may at times incur indebtedness in excess of its long-term leverage targets, in advance of raising the additional equity necessary to repay such indebtedness and maintain its long-term leverage target. Any increase in the Company’s leverage could, among other things, limit the Company’s ability to obtain additional financing for working capital, investment in subsidiaries, capital expenditures, debt service requirements, acquisitions and general corporate or other purposes; restrict the Company’s flexibility and discretion to operate its business; limit the Company’s ability to declare dividends; require the Company to dedicate a portion of cash flows from operations to the payment of interest on its existing indebtedness, in which case such cash flows will not be available for other purposes; cause ratings agencies to re-evaluate or downgrade the Company’s existing credit ratings; expose the Company to increased interest expense on borrowings at variable rates; limit the Company’s ability to adjust to changing market conditions; place the Company at a competitive disadvantage compared to its competitors; make the Company vulnerable to any downturn in general economic conditions; and render the Company unable to make expenditures that are important to its future growth strategies.
The Company will need to refinance or reimburse amounts outstanding under the Company’s existing consolidated indebtedness over time. There can be no assurance that any indebtedness of the Company will be refinanced or that additional financing on commercially reasonable terms will be obtained, if at all. In the event that such indebtedness cannot be refinanced, or if it can be refinanced on terms that are less favourable than the current terms, the Company's cashflows and the ability of the Company to declare dividends may be adversely affected.
The ability of the Company to meet its debt service requirements will depend on its ability to generate cash in the future, which depends on many factors, including the financial performance of the Company, debt service obligations, the realization of the anticipated benefits of acquisition and investment activities, and working capital and capital expenditure requirements. In addition, the ability of the Company to borrow funds in the future to make payments on outstanding debt will depend on the satisfaction of covenants in existing credit agreements and other agreements. A failure to comply with any covenants or obligations under the Company’s consolidated indebtedness could result in a default under one or more such instruments, which, if not cured or waived, could result in the termination of dividends by the Company and permit acceleration of the relevant indebtedness. If such indebtedness were to be accelerated, there can be no assurance that the assets of the Company would be sufficient to repay such indebtedness in full. There can also be no assurance that the Company will generate cash flows in amounts sufficient to pay outstanding indebtedness or to fund any other liquidity needs.
Interest Rate Risk
The majority of debt outstanding in APUC and its subsidiaries is subject to a fixed rate of interest and as such is not subject to significant interest rate risk in the short to medium term time horizon.
Borrowings subject to variable interest rates can vary significantly from month to month, quarter to quarter and year to year. APUC does not actively manage interest rate risk on its variable interest rate borrowings due to the primarily short term and revolving nature of the amounts drawn.

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

Based on amounts outstanding as at December 31, 2019, the impact to interest expense from changes in interest rates are as follows:

• | The Corporate Credit Facility is subject to a variable interest rate and had $143.0 million outstanding as at December 31, 2019. As a result, a 100 basis point change in the variable rate charged would impact interest expense by $1.4 million annually;

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

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

Tax Risk and Uncertainty
The Company is subject to income and other taxes primarily in the United States and Canada. Changes in tax laws or interpretations thereof in the jurisdictions in which it does business could adversely affect the Company's results from operations, returns to shareholders and cash flow.
The Company cannot provide assurance that the Canada Revenue Agency, the Internal Revenue Service or any other applicable taxation authority will agree with the tax positions taken by the Company, including with respect to claimed expenses and the cost amount of the Company's depreciable properties. A successful challenge by an applicable taxation authority regarding such tax positions could adversely affect the results of operations and financial position of the Company.
Development by the Company of renewable power generation facilities in the United States depends in part on federal tax credits and other tax incentives. These credits are currently subject to a multi-year step-down. While recently enacted U.S. Tax Reform legislation did extend some of the credits, at reduced levels, for renewable power generation facilities that begin construction in 2020, there can be no assurance that there will be further extensions in the future or whether the reduced credits are sufficient to support continued development and construction of renewable power facilities in the United States. Moreover, if the Company is unable to complete construction on current or planned projects on anticipated schedules, the incentives may no longer be available or substantially reduced which may be insufficient to support continued development or may result in substantially reduced financial benefits from facilities or long-term investment in facilities (potentially resulting in a write down of a portion of a facility whether held directly or through an equity investee) that the Company is committed to complete. In addition, the Company has entered into certain tax equity financing transactions with financial partners for certain of its renewable power facilities in the United States, under which allocations of future cash flows to the Corporation from the applicable facility could be adversely affected in the event that there are changes in U.S. tax laws that apply to facilities previously placed in service.
U.S. Tax Reform
On December 22, 2017, H.R. 1, the Tax Cuts and Jobs Act was signed into law which resulted in significant changes to U.S. tax law that affect the Company. The U.S. Department of Treasury has released proposed regulations related to business interest expense limitations, Base Erosion Anti-Abuse Tax, and anti-hybrid structures as part of the implementation of U.S. Tax Reform. Some of the proposed regulations were finalized during 2019. Many of the regulations are still in proposed form and are subject to change in the regulatory review process which is expected to be completed during 2020. The timing or impacts of any future changes in tax laws, including the impacts of proposed regulations, cannot be predicted. As a result, there may be future impacts on the results of operations, financial condition and cash flows of the Company.

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

Credit/Counterparty Risk
APUC and its subsidiaries, through its long term PPA's, trade receivables, derivative financial instruments and short term investments, are subject to credit risk with respect to the ability of customers and other counterparties to perform their obligations to the Company.
The following chart sets out the Company’s 10 largest customers and their credit ratings:

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

1 | Ratings by DBRS, Moody’s, or S&P.

The Renewable Energy Group's revenues are approximately 15% of total Company revenues. Approximately 87% of the Renewable Energy Group's revenues are earned from large utility customers having a credit rating of Baa2 or better by Moody's, or BBB or higher by S&P, or BBB or higher by DBRS.
The remaining revenue of the Company is primarily earned by the Regulated Services Group. In this regard, the credit risk attributed to the Regulated Services Group's accounts receivable balances at the water and wastewater distribution systems total $22.1 million which is spread over approximately 168,000 connections, resulting in an average outstanding balance of approximately $130 dollars per connection.
The natural gas distribution systems accounts receivable balances related to the natural gas utilities total $99.3 million, while electric distribution systems accounts receivable balances related to the electric utilities total $90.8 million. The natural gas and electrical utilities both derive over 80% of their revenue from residential customers and have a per connection average outstanding balance of $269 dollars and $340 dollars respectively.
Adverse conditions in the energy industry or in the general economy, as well as circumstances of individual customers or counterparties, may adversely affect the ability of a customer or counterparty to perform as required under its contract with the Company. Losses from a utility customer may not be offset by bad debt reserves approved by the applicable utility regulator. If a customer under a long-term PPA with the Renewable Energy Group is unable to perform, the Renewable Energy Group may be unable to replace the contract on comparable terms, in which case sales of power (and, if applicable, RECs and ancillary services) from the facility would be subject to market price risk and may require refinancing of indebtedness related to the facility or otherwise have a material adverse effect. Default by other counterparties, including counterparties to hedging contracts that are in an asset position and to short-term investments, also could adversely affect the financial results of the Corporation.
Market Price Risk
The Renewable Energy Group assets subject to long term PPA's are not exposed to market risk for this portion of its portfolio. Where a generating asset is not covered by a PPA, the Renewable Energy Group may seek to mitigate market risk exposure by entering into financial or physical power hedges requiring that a specified amount of power be delivered at a specified time in return for a fixed price. There is a risk that the Company is not able to generate the specified amount of power at the specified time resulting in production shortfalls under the hedge that then requires the Company to purchase power in the merchant market. To mitigate the risk of production shortfalls under hedges, the Renewable Energy Group generally seeks to structure hedges to cover less than 100% of the anticipated production, thereby reducing the risk of not producing the minimum hedge quantities. Nevertheless, due to unpredictability in the natural resource or due to grid curtailments or mechanical failures, production shortfalls may be such that the Renewable Energy Group may still be forced to purchase power in the merchant market at prevailing rates to settle against a hedge.

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

Hedges currently put in place by the Renewable Energy Group for its operating facilities along with residual exposures to the market are detailed below:
The Minonk, Senate and Sandy Ridge Wind Facilities with a combined annual LTAR of 1,352 GW-hrs have financial hedges in place until the end of 2025 which are structured to hedge an average of 66.3% of annual LTAR against exposure to the applicable hub current spot market rates. The annual average unhedged production based on LTAR is approximately 455 GW-hrs annually.
Under each of the above noted hedges, if production is not sufficient to meet the unit quantities under the hedge, the shortfall must be purchased in the open market at market rates. The effect of this risk exposure could be material but cannot be quantified as it is dependent on both the amount of shortfall and the market price of electricity at the time of the shortfall.
In addition to the above noted hedges, from time to time the Renewable Energy Group enters into short-term derivative contracts (usually with terms of one to three months) to further mitigate market price risk exposure due to production variability. As at December 31, 2019, the Renewable Energy Group had entered into hedges with a cumulative notional quantity of 148,520 MW-hrs.
The January 1, 2013 acquisition of the Shady Oaks Wind Facility included a power sales contract, which commenced on June 1, 2012 for a 20 year period. The power sales contract is structured to hedge the preponderance of the Shady Oaks Wind Facility’s production volume against exposure to PJM ComEd Hub current spot market rates. For the unhedged portion of production based on expected long term average production, each $10 per MW-hr change in market prices would result in a change in revenue of approximately $0.5 million for the year.
The Company has elected the fair value option under ASC 825, Financial Instruments to account for its investment in Atlantica, with changes in fair value reflected in the annual audited consolidated statement of operations. As a result, each dollar change in the traded price of Atlantica shares will correspondingly affect the Company's Net Earnings by approximately $44.9 million.
Commodity Price Risk
The Regulated Services Group is exposed to energy and natural gas price risks at its electric and natural gas systems. The Renewable Energy Group's exposure to commodity prices is primarily limited to exposure to natural gas price risk. In this regard, a discussion of these risks are set out as follows:
Regulated Services Group
The CalPeco Electric System provides electric service to the Lake Tahoe California basin and surrounding areas at rates approved by the California Public Utilities Commission ("CPUC"). The CalPeco Electric System purchases the energy, capacity, and related service requirements for its customers from NV Energy via a PPA at rates reflecting NV Energy’s system average costs.
The CalPeco Electric System's tariffs allow for the pass-through of energy costs to its rate payers on a dollar for dollar basis, through the ECAC mechanism, which allows for the recovery or refund of changes in energy costs that are caused by the fluctuations in the price of fuel and purchased power. On a monthly basis, energy costs are compared to the CPUC approved base tariff energy rates and the difference is deferred to a balancing account. Annually, based on the balance of the ECAC balancing account, if the ECAC revenues were to increase or decrease by more than 5%, the CalPeco Electric System's ECAC tariff allows for a potential adjustment to the ECAC rates which would eliminate the risk associated with the fluctuating cost of fuel and purchased power.
The Granite State Electric System is an open access electric utility allowing for its customers to procure commodity services from competitive energy suppliers. For those customers that do not choose their own competitive energy supplier, Granite State Electric System provides a Default Service offering to each class of customers through a competitive bidding process. This process is undertaken semi-annually for all Default Service customers. The winning bidder is obligated to provide a full requirements service based on the actual needs of the Granite State Electric System’s Default Service customers. Since this is a full requirements service, the winning bidder(s) take on the risk associated with fluctuating customer usage and commodity prices. The supplier is paid for the commodity by the Granite State Electric System which in turns receives pass-through rate recovery through a formal filing and approval process with the NHPUC on a semi-annual basis. The Granite State Electric System is only committed to the winning Default Service supplier(s) after approval by the NHPUC so that there is no risk of commodity commitment without pass-through rate recovery.
The EnergyNorth Natural Gas System purchases pipeline capacity, storage and commodity from a variety of counterparties. The EnergyNorth Natural Gas System's portfolio of assets and its planning and forecasting methodology are commonly approved by the NHPUC bi-annually through Least Cost Integrated Resource Plan filing. In addition, EnergyNorth Natural Gas System files with the NHPUC for recovery of its transportation and commodity costs on a semi-annual basis through the Cost of Gas ("COG") filing and approval process. The EnergyNorth Natural Gas System establishes rates for its customers based on the NHPUC approval of its filed COG. These rates are designed to fully recover its anticipated transportation and commodity costs. In order to minimize commodity price fluctuations, the EnergyNorth Natural Gas System locks in a fixed price basis for approximately 18% of its normal winter period purchases under a NHPUC approved hedging program. All costs associated with the fixed basis hedging program are allowed to be a pass-through to customers through the COG filing and the approved

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

rates in said filing. Should commodity prices increase or decrease relative to the initial semi-annual COG rate filing, the EnergyNorth Natural Gas System has the right to automatically adjust its rates going forward in order to minimize any under or over collection of its gas costs. In addition, any under collections may be carried forward with interest to the next year’s corresponding COG filing, i.e. winter to winter and summer to summer.
The Midstates Gas Systems purchases pipeline capacity, storage and commodity from a variety of counterparties, and files with the three individual state commissions for recovery of its transportation and commodity costs through an annual Purchase Gas Adjustment (“PGA”) filing and approval process. The Midstates Gas Systems establishes rates for its customers within the PGA filing and these rates are designed to fully recover its anticipated transportation, storage and commodity costs. In order to minimize commodity price fluctuations, the Company has implemented a commodity hedging program designed to hedge approximately 25-50% of its non-storage related commodity purchases. All gains and losses associated with the hedging program are allowed to be a pass-through to customers through the PGA filing and are embedded in the approved rates in said filing. Rates can be adjusted on a monthly or quarterly basis in order to account for any commodity price increase or decrease relative to the initial PGA rate, minimizing any under or over collection of its gas costs. Similar to the Midstates Gas Systems, the Empire Gas System serves customers in Missouri, and also implements a commodity hedging program designed to hedge 70 to 90% of its winter demand inclusive of storage volumes withdrawn during the winter period. All related costs are embedded in approved rates and are passed-through to customers in the PGA. The Empire Gas System is permitted to file an Actual Cost Adjustment (“ACA”) once a year which also includes a PGA filing. In addition to the ACA filing, three more optional PGA filings are allowed during the year. The Empire Gas Systems ACA year is from September 1 to August 31 for each year.
The Georgia (Peach State) Gas System purchases pipeline capacity, storage and commodity from a variety of counterparties, and files with the Georgia Public Service Commission ("PSC") for recovery of its transportation, storage and commodity costs through a monthly PGA filing process. The Peach State Gas System establishes rates for its customers within the PGA filings and these rates are designed to fully recover its anticipated transportation, storage and commodity costs. In order to minimize commodity price fluctuations, the annual Gas Supply Plan filed by the Company and approved by the Georgia PSC includes a commodity hedging program designed to hedge approximately 30% of its non-storage related commodity purchases during the winter months. All gains and losses associated with the hedging program are passed through to customers in the PGA filings and are embedded in the approved rates in such filings. Rates can be adjusted on a monthly basis in order to account for any differences in gas costs relative to the amounts assumed in the PGA filings, minimizing any under or over collection of its gas costs.
The Empire Electric System has a fuel cost recovery mechanism in all of its jurisdictions, as such impacts on net income exposure to commodity cost fluctuations are significantly reduced. However, cash flow could still be impacted by any increased expenditures. The Empire Electric System met approximately 41% of its 2019 generation fuel supply need through coal. Approximately 97% of its 2019 coal supply was Western coal. The Empire Electric System had contracts and binding proposals to supply a portion of the fuel for its coal plants through 2019. Those contracts and inventory on hand satisfied the anticipated fuel requirements for the Asbury Coal Facility. The Asbury Coal Facility is scheduled to be retired in March 2020.
The Empire Electric Systems natural gas procurement program for electrical generation is designed to manage costs to mitigate volatile natural gas prices. The Empire Electric System periodically enters into fixed price contracts with counterparties to hedge future natural gas prices in an attempt to lessen the volatility in fuel expenditures. Generally, the over/under variances associated with the hedging program are passed through to customers in the fuel adjustment clause assuming they are deemed to be prudently incurred.
Renewable Energy Group
The Sanger Thermal Facility’s PPA includes provisions which reduce its exposure to natural gas price risk. In this regard, a $1.00 increase in the price of natural gas per MMBTU, based on expected production levels, would result in a decrease in net revenue by approximately $0.1 million on an annual basis.
The Windsor Locks Thermal Facility’s Energy Services Agreement includes provisions which reduce its exposure to natural gas price risk but has exposure to market rate conditions for sales above those to its primary customer. In this regard, a $1.00 increase in the price of natural gas per MMBTU, based on expected production levels, would result in a decrease in net revenue by approximately $0.4 million on an annual basis.
The Maritime region provides short-term energy requirements to various customers at fixed rates. The energy requirements of these customers are estimated at approximately 190,000 MW-hrs in fiscal 2020, of which 181,000 MW-hrs is presently contracted. While the Tinker Hydro Facility is expected to provide the majority of the energy required to service these customers, the Maritime region anticipates having to purchase approximately 41,000 MW-hrs of its energy requirements at the ISO-NE spot rates to supplement self-generated energy should the Maritime region not be able to reach the estimated 190,000 MW-hrs. The risk associated with the expected market purchases of 41,000 MW-hrs is mitigated through the use of financial energy hedge contracts which cover all of the Maritime region's anticipated purchases during the year at an average rate of approximately $39 per MW-hr.

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

OPERATIONAL RISK MANAGEMENT
Succession Planning and Leadership Development
On February 5, 2020, APUC announced the appointment of Arun Banskota to the newly-created position of President. Mr. Banskota will work closely with Chief Executive Officer Ian Robertson and other members of the Executive Team to transition into the role of Chief Executive Officer in 2020.
APUC also announced that David Bronicheski, Chief Financial Officer, is retiring in the fall of 2020, and that Arthur Kacprzak, Vice President, Treasury and Treasurer, has been promoted to Senior Vice President and Deputy Chief Financial Officer.
There can be no assurance that leadership transitions will be successful and the transitions may have an adverse impact to APUC and its business.
Mechanical and Operational Risks
APUC's profitability could be impacted by, among other things, equipment failure, the failure of a major customer to fulfill its contractual obligations under its PPA, reductions in average energy prices, a strike or lock-out at a facility, natural disasters, diseases (including the 2019 Novel Coronavirus) and other force majeure events, interruption in supply chain and expenses related to claims or clean-up to adhere to environmental and safety standards.
The Regulated Services Group's water and wastewater distribution systems operate under pressurized conditions within pressure ranges approved by regulators. Should a water distribution network become compromised or damaged, the resulting release of pressure could result in serious injury or death to individuals or damage to other property.
The Regulated Services Group's electric distribution systems are subject to storm events, usually winter storm events, whereby power lines can be brought down, with the attendant risk to individuals and property. In addition, in forested areas, power lines brought down by wind can ignite forest fires which also bring attendant risk to individuals and property.
The Regulated Services Group's natural gas distribution systems are subject to risks which may lead to fire and/or explosion which may impact life and property. Risks include third party damage, compromised system integrity, type/age of pipelines, and severe weather events.
The Renewable Energy Group's hydro assets utilize dams to pond water for generation and if the dams fail/breach potentially catastrophic amounts of water would flood downriver from the facility. The dams can be subjected to drought conditions and lose the ability to generate during peak load conditions, causing the facilities to fall short of either hedged or PPA committed production levels. The risks of the hydro facilities are mitigated by regular dam inspections and a maintenance program of the facility to lessen the risk of dam failure.
The Renewable Energy Group's wind assets could catch on fire and, depending on the season, could ignite significant amounts of forest or crop downwind from the wind farms. The wind units could also be affected by large atmospheric conditions, which will lower wind levels below our PPA and hedge minimum production levels. The wind units can experience failures in the turbine blades or in the supporting towers. Production risks associated with the wind turbine generators failures is mitigated by properly maintaining the units, using long term maintenance agreements with the turbine O&Ms which provide for regular inspections and maintenance of property, and liability insurance policies. Icing can be mitigated by shutting down the unit as icing is detected at the site.
The Renewable Energy Group's Thermal Energy Division uses natural gas and oil, and produces exhaust gases, which if not properly treated and monitored could cause hazardous chemicals to be released into the atmosphere. The units could also be restricted from purchasing gas/oil due to either shortages or pollution levels, which could hamper output of the facility. The mechanical and operational risks at the thermal facilities are mitigated through the regular maintenance of the boiler system, and by continual monitoring of exhaust gases. Fuel restrictions can be hedged in part by long term purchases.
All of the Renewable Energy Group's electric generating stations are subject to mechanical breakdown. The risk of mechanical breakdown is mitigated by properly maintaining the units and by regular inspections.
These risks are mitigated through the diversification of APUC’s operations, both operationally and geographically, the use of regular maintenance programs, including pipeline safety programs and compliance programs, and maintaining adequate insurance, an active Enterprise Risk Management program and the establishment of reserves for expenses.
Regulatory Risk
Profitability of APUC businesses is, in part, dependent on regulatory climates in the jurisdictions in which those businesses operate. In the case of some of Renewable Energy Group's hydroelectric facilities, water rights are generally owned by governments that reserve the right to control water levels, which may affect revenue.
The Regulated Services Group’s facilities are subject to rate setting by state regulatory agencies. The Regulated Services Group operates in 13 different states and 1 province and therefore is subject to regulation from 14 different regulatory agencies. The time between the incurrence of costs and the granting of the rates to recover those costs by state regulatory agencies is

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

known as regulatory lag. As a result of regulatory lag, inflationary effects may impact the ability to recover expenses, and profitability could be impacted. In order to mitigate this exposure, the Regulated Services Group seeks to obtain approval for regulatory constructs in the states in which it operates to allow for timely recovery of operating expenses. A fundamental risk faced by any regulated utility is the disallowance of costs to be placed into its revenue requirement by the utility's regulator. To the extent proposed costs are not allowed into rates, the utility will be required to find other efficiencies or cost savings to achieve its allowed returns.
The Regulated Services Group regularly works with its governing authorities to manage the affairs of the business, employing both local, state level, and corporate resources.
On December 22, 2017, the Tax Cuts and Jobs Act was signed into law which resulted in significant changes to U.S. tax law. Amongst other things, the Act reduced the federal corporate income tax rates from 35% to 21%. The change in corporate tax rates has had an impact on regulatory revenue requirements of most public utilities, including the Regulated Services Group. The Regulated Services Group obtained orders from the majority of its principal regulators, resulting in the reduction of customer rates in connection with the reduction in tax rates. Since the Company has not yet received rate orders addressing all matters related to U.S. Tax Reform for all of its utilities, the full impact of rate reductions related to U.S. Tax Reform is not known.
Condemnation Expropriation Proceedings
The Regulated Services Group's distribution systems could be subject to condemnation or other methods of taking by government entities under certain conditions. Any taking by government entities would legally require fair compensation to be paid. Determination of such fair compensation is undertaken pursuant to a legal proceeding and, therefore, there is no assurance that the value received for assets taken will be in excess of book value.
Apple Valley Condemnation Proceedings
On January 7, 2016, the Town of Apple Valley filed a lawsuit seeking to condemn the utility assets of the Regulated Services Group (Apple Valley Ranchos Water) Corp ("Liberty Apple Valley"). The lawsuit will be adjudicated in phases. In the first phase, the Court will determine whether to allow the taking by the Town; under California law, the taking will be allowed unless Liberty Apple Valley proves there is not a “public necessity” for the taking. If Liberty Apple Valley prevails, the case is concluded and the Town will be required to compensate Liberty Apple Valley for its litigation expenses. However, if the Court determines that the taking is allowed, there will be a second phase of the trial in which a jury will determine the amount of compensation owed for the taking based upon the fair market value of the assets being condemned. The right to take trial began on October 23, 2019, and is expected to continue until March 2020 with a judicial decision on the right to take expected in the third quarter of 2020. If, following that trial, there is a need for a second phase to determine compensation, that trial can be expected to occur six to twelve months after the conclusion of the first phase.
Acquisition Risk
Part of the Company's business strategy is to acquire new generating stations and existing regulated utilities. The Company's acquisition strategy introduces exposures inherent to such transactions that may adversely affect the results of an acquisition, including failure to obtain required approvals, delays in implementation or unexpected costs or liabilities, as well as the risk of failing to realize operating benefits or synergies. The Company mitigates these risks by following systematic procedures for integrating acquisitions, applying strict financial metrics to any potential acquisition and subjecting the process to close monitoring and review by the Board of Directors.
When acquisitions occur, significant demands can be placed on the Company’s managerial, operational and financial personnel and systems. No assurance can be given that the Company’s systems, procedures and controls will be adequate to support the expansion of the Company’s operations resulting from the acquisition. The Company’s future operating results will be affected by the ability of its officers and key employees to manage changing business conditions and to implement and improve its operational and financial controls and reporting systems.
The Company's growth strategy may be constrained by factors associated with the maintenance of its BBB flat investment grade credit ratings. These factors include: (i) constraints on maximum leverage, (ii) the proportion of EBITDA (as determined by applicable rating agency methodologies) required to be generated from the Regulated Services Group, and (iii) the geographies in which APUC can operate in scale. There can be no assurance that these constraints will not negatively impact the Company's ability to successfully execute on available growth opportunities. The business mix target may from time to time require APUC to grow its Regulated Services Group or implement other strategies in order to pursue investment opportunities within its Renewable Energy Group.
International Investment Risk
The Company’s investment in Atlantica exposes the Company to certain risks that are particular to Atlantica’s business and the markets in which Atlantica operates.
Atlantica owns, manages and acquires renewable energy, conventional power, electric transmission lines and water assets in certain jurisdictions where the Company may not operate. The Company, through its investment in Atlantica, is indirectly

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

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

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

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

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

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

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

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

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

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

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

Asset Retirement Obligations
APUC and its subsidiaries complete periodic reviews of potential asset retirement obligations that may require recognition. As part of this process, APUC and its subsidiaries consider the contractual requirements outlined in their operating permits, leases, and other agreements, the probability of the agreements being extended, the ability to quantify such expense, the timing of incurring the potential expenses, as well as other factors which may be considered in evaluating if such obligations exist and in estimating the fair value of such obligations.
In conjunction with acquisitions and developed projects, the Company assumed certain asset retirement obligations. The asset retirement obligations mainly relate to legal requirements for: (i) removal or decommissioning of power generating facilities; (ii) cut (disconnect from the distribution system), purge (clean of natural gas and PCB contaminants), and cap gas mains within the gas distribution and transmission system when mains are retired in place, or dispose of sections of gas mains when removed from the pipeline system; (iii) clean and remove storage tanks containing waste oil and other waste contaminants; and (iv) remove asbestos upon major renovation or demolition of structures and facilities.
Cycles and Seasonality
Regulated Services Group
The Regulated Services Group's demand for water is affected by weather conditions and temperature. Demand for water during warmer months is generally greater than cooler months due to requirements for irrigation, swimming pools, cooling systems and other outside water use. If there is above normal rainfall or rainfall is more frequent than normal the demand for water may decrease, adversely affecting revenues.
The Regulated Services Group's demand for energy from its electric distribution systems is primarily affected by weather conditions and conservation initiatives. The Regulated Services Group provides information and programs to its customers to encourage the conservation of energy. In turn, demand may be reduced which could have short term adverse impacts on revenues.
The Regulated Services Group's primary demand for natural gas from its natural gas distribution systems is driven by the seasonal heating requirements of its residential, commercial, and industrial customers. The colder the weather the greater the demand for natural gas to heat homes and businesses. As such, the natural gas distribution systems demand profiles typically peaks in the winter months of January and February and declines in the summer months of July and August. Year to year variability also occurs depending on how cold the weather is in any particular year.
The Company attempts to mitigate the above noted risks by seeking regulatory mechanisms during rate review proceedings. While not all regulatory jurisdictions have approved mechanisms to mitigate demand fluctuations, to date, the Regulated Services Group has successfully obtained regulatory approval to implement such decoupling mechanisms in 7 of 13 states. An example of such a mechanism is seen at the Peach State Gas System in Georgia, where a weather normalization adjustment is applied to customer bills during the months of October through May that adjusts commodity rates to stabilize the revenues of the utility for changes in billing units attributable to weather patterns.
Renewable Energy Group
The Renewable Energy Group's hydroelectric operations are impacted by seasonal fluctuations and year to year variability of the available hydrology. These assets are primarily “run-of-river” and as such fluctuate with natural water flows. During the winter and summer periods, flows are generally lower while during the spring and fall periods flows are generally higher. The ability of these assets to generate income may be impacted by changes in water availability or other material hydrologic events within a watercourse. Year to year the level of hydrology varies, impacting the amount of power that can be generated in a year.
The Renewable Energy Group's wind generation facilities are impacted by seasonal fluctuations and year to year variability of the wind resource. During the fall through spring period, winds are generally stronger than during the summer periods. The ability of these facilities to generate income may be impacted by naturally occurring changes in wind patterns and wind strength.
The Renewable Energy Group's solar generation facilities are impacted by seasonal fluctuations and year to year variability in the solar radiance. For instance, there are more daylight hours in the summer than there are in the winter, resulting in higher production in the summer months. The ability of these facilities to generate income may be impacted by naturally occurring changes in solar radiance.
The Company attempts to mitigate the above noted natural resource fluctuation risks by acquiring or developing generating stations in different geographic locations.
Development and Construction Risk
The Company actively engages in the development and construction of new power generation facilities. There is always a risk that material delays and/or cost overruns could be incurred in any of the projects planned or currently in construction affecting the Company’s overall performance. There are risks that actual costs may exceed budget estimates, delays may occur in obtaining permits and materials, suppliers and contractors may not perform as required under their contracts, there may be

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

inadequate availability, productivity or increased cost of qualified craft labor, start-up activities may take longer than planned, the scope and timing of projects may change, and other events beyond the Company's control may occur that may materially affect the schedule, budget, cost and performance of projects. Regulatory approvals can be challenged by a number of mechanisms which vary across state and provincial jurisdictions. Such permitting challenges could identify issues that may result in permits being modified or revoked.
Risks Specific to Renewable Generation Projects:
The strength and consistency of the wind resource will vary from the estimate set out in the initial wind studies that were relied upon to determine the feasibility of the wind facility. If weather patterns change or the historical data proves not to accurately reflect the strength and consistency of the actual wind, the assumptions underlying the financial projections as to the amount of electricity to be generated by the facility may be different and cash could be impacted.
The amount of solar radiance will vary from the estimate set out in the initial solar studies that were relied upon to determine the feasibility of the solar facility. If weather patterns change or the historical data proves not to accurately reflect the strength and consistency of the solar radiance, the assumptions underlying the financial projections as to the amount of electricity to be generated by the facility may be different and cash could be impacted.
For certain of its development projects, the Company relies on financing from third party tax equity investors. These investors typically provide funding upon commercial operation of the facility. Should certain facilities not meet the conditions required for tax equity funding, expected returns from the facilities may be impacted.
Development by the Renewable Energy Group of renewable power generation facilities in the United States depends in part on federal tax credits and other tax incentives. These incentives are currently subject to a multi-year step-down. The first step down occurs on December 31, 2020. APUC currently has a number of significant projects in construction that could be materially adversely affected if they are not placed in service by this date.
In February 2020, APUC received force majeure notices from certain of its turbine suppliers related to the 2019 Novel Coronavirus outbreak. The notices relate to wind energy projects from both the Regulated Services Group and Renewable Energy Group and a solar project from the Renewable Energy Group. While the exact impacts of the 2019 Novel Coronavirus outbreak on APUC and its projects remain unknown, manufacturing and delivery delays caused by the 2019 Novel Coronavirus could adversely affect its projects, including (a) causing one or more projects scheduled for completion in 2020 to not be placed in service until 2021 or (b) adversely impacting the availability of tax equity or other financing. APUC is working with its suppliers, contractors and advisors in an effort to mitigate the impacts on its projects, but there can be no assurance that such efforts will be successful.
Litigation Risks and Other Contingencies
APUC and certain of its subsidiaries are involved in various litigation, claims and other legal and regulatory proceedings that arise from time to time in the ordinary course of business. Any accruals for contingencies related to these items are recorded in the financial statements at the time it is concluded that a material financial loss is likely and the related liability is estimable. Anticipated recoveries under existing insurance policies are recorded when reasonably assured of recovery.
Claim by Gaia Power Inc.
On October 30, 2018, Gaia Power Inc. (“Gaia”) commenced an action in the Ontario Superior Court of Justice against APUC and certain of its subsidiaries, claiming damages of not less than C$345 million and punitive damages in the sum of C$25 million. The action arises from Gaia’s 2010 sale, to a subsidiary of APUC, of Gaia’s interest in certain proposed wind farm projects in Canada. Pursuant to a 2010 royalty agreement, Gaia is entitled to royalty payments if the projects are developed and achieve certain agreed targets.
The parties have since agreed to arbitrate the matter pursuant to the royalty agreement's arbitration clause. APUC and the other respondents have delivered their responses to Gaia's notice of arbitration, and the parties are currently in the process of exchanging documentary productions. It is too early to determine the likelihood of success in this lawsuit, however APUC intends to vigorously defend it.
Information Security Risk
The Company's information technology systems may be vulnerable to potential risks from cybersecurity attacks. Attacks can be caused by malware, viruses, email attachments, acts of war or terrorism and can originate from individuals from both inside and outside the organization. An attack could result in service disruptions, system failures, the disclosure of personal customer and employee information, and could lead to an adverse effect on the Company's financial performance. A breach of personal or confidential information may also occur as a result of non-cyber means, such as breach of physical security and device theft. Should a material breach occur the Company may not be able to recover all costs and losses through insurance, legal or regulatory processes.

Algonquin Power & Utilities Corp. - Management Discussion & Analysis | 50

Energy Consumption and Advancement in Technologies Risk
The Regulated Services Group's operations are subject to changes in demand for energy which are impacted by general economic conditions, customer's focus on energy efficiency, and advancements in new technologies.
The Regulated Services Group is actively involved in working with governments and customers to ensure these changes in consumption do not negatively impact the services provided. Furthermore, through its strategic initiatives the Regulated Services Group is constantly looking for ways to maintain the Company's competitive advantage.
Uninsured Risk
The Company maintains insurance for accidental loss and potential liabilities to third parties in accordance with the industry practice. However, there are certain elements of the Regulated Services Group's regulated utilities that are not fully insured as the cost of the coverage is not economically viable. In the event that a liability event or loss is not covered through insurance the Regulated Services Group would apply to their respective regulator to request recovery through increased customer rates. Cost recovery through this mechanism is subject to regulatory approval and is therefore uncertain.
Insurance coverage for the rest of the Company is also subject to policy conditions and exclusions, coverage limits, and various deductibles, and not all types of liabilities and losses may be covered by insurance, in which case the Company may be financially exposed.
QUARTERLY FINANCIAL INFORMATION
The following is a summary of unaudited quarterly financial information for the eight quarters ended December 31, 2019:

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

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

The quarterly results are impacted by various factors including seasonal fluctuations and acquisitions of facilities as noted in this MD&A.
Quarterly revenues have fluctuated between $343.6 million and $494.8 million over the prior two year period. A number of factors impact quarterly results including acquisitions, seasonal fluctuations, and winter and summer rates built into the PPAs.

Algonquin Power & Utilities Corp. - Management Discussion & Analysis | 51

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

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

DISCLOSURE CONTROLS AND PROCEDURES
APUC's management carried out an evaluation as of December 31, 2019, under the supervision of and with the participation of APUC’s Chief Executive Officer (“CEO”) and Chief Financial Officer (“CFO”), of the effectiveness of the design and operations of APUC’s disclosure controls and procedures (as defined in Rule 13a-15(e) and Rule 15d-15 (e) under the Securities Exchange Act of 1934, as amended (the “Exchange Act”)). Based on that evaluation, the CEO and the CFO have concluded that as of December 31, 2019, APUC’s disclosure controls and procedures are effective to provide reasonable assurance that information required to be disclosed by APUC in reports that it files or submits under the Exchange Act is recorded, processed, summarized, and reported within the time periods specified in SEC rules and forms, and is accumulated and communicated to management, including the CEO and CFO, as appropriate, to allow timely decisions regarding required disclosure.
MANAGEMENT REPORT ON INTERNAL CONTROLS OVER FINANCIAL REPORTING
Management, including the CEO and the CFO, is responsible for establishing and maintaining internal control over financial reporting (as defined in Rules 13a-15(f) under the Exchange Act) to provide reasonable, but not absolute, assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with U.S. GAAP.
The Company's internal control over financial reporting framework includes those policies and procedures that (i) pertain to the maintenance of records that, in reasonable detail, accurately and fairly reflect the transactions and dispositions of the assets of the Company, (ii) provide reasonable assurance that transactions are recorded as necessary to permit preparation of financial statements in accordance with U.S. GAAP, and that receipts and expenditures of the Company are being made only in accordance with authorizations of management and directors of the Company; and (iii) provide reasonable assurance regarding prevention or timely detection of unauthorized acquisition, use or disposition of the Company's assets that could have a material effect on the Company's consolidated financial statements.
Due to its inherit limitations, disclosure controls and procedures or internal control over financial reporting may not prevent or detect all misstatements based on error of fraud. Further, the effectiveness of internal control is subject to the risk that controls may become inadequate because of changes in conditions, or that the degree of compliance with policies or procedures may change.
During the year ended December 31, 2019, the Company acquired St. Lawrence Gas and New Brunswick Gas. Management is in the process of evaluating the existing controls and procedures of St. Lawrence Gas and New Brunswick Gas and integrating financial reporting and controls for St. Lawrence Gas and New Brunswick Gas into the Company's internal control over financial reporting. The financial information for these acquisitions is included in this MD&A and in Note 3 in the annual audited consolidated financial statements. As permitted under applicable laws due to the complexity associated with assessing internal controls during integration efforts, the Company excluded these acquisitions from its evaluation of the effectiveness of the

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

Company's internal controls over financial reporting as of December 31, 2019 (representing approximately 4% of our total assets as of December 31, 2019 and approximately 2% of our revenues for the year ended December 31, 2019). Management assessed the effectiveness of the Company's internal control over financial reporting as of December 31, 2019, based on the framework established in Internal Control - Integrated Framework (2013) issued by COSO. This assessment included review of the documentation of controls, evaluation of the design effectiveness of controls, testing of the operating effectiveness of controls, and a conclusion on this evaluation. Based on this assessment, management concluded that the Company's internal control over financial reporting was effective as of December 31, 2019 to provide reasonable assurance regarding the reliability of financial reporting and the preparation of consolidated financial statements for external reporting purposes in accordance with U.S. GAAP. Management reviewed the results of its assessment with the Audit Committee of the Board of Directors of APUC.
CHANGES IN INTERNAL CONTROLS OVER FINANCIAL REPORTING
For the twelve months ended December 31, 2019, there has been no change in the Company’s internal controls over financial reporting that has materially affected, or is reasonably likely to materially affect, the Company’s internal controls over financial reporting.
INHERENT LIMITATIONS ON EFFECTIVENESS OF CONTROLS
Due to its inherent limitations, disclosure controls and procedures or internal control over financial reporting may not prevent or detect all misstatements based on error of fraud. Further, the effectiveness of internal control is subject to the risk that controls may become inadequate because of changes in conditions, or that the degree of compliance with policies or procedures may change.
CRITICAL ACCOUNTING ESTIMATES AND POLICIES
APUC prepared its consolidated financial statements in accordance with U.S. GAAP. The preparation of consolidated financial statements requires management to make estimates and assumptions that affect the reported amounts of assets and liabilities, related amounts of revenues and expenses, and disclosure of contingent assets and liabilities. Significant areas requiring the use of management judgment relate to the scope of consolidated entities, useful lives and recoverability of depreciable assets, the measurement of deferred taxes and the recoverability of deferred tax assets, rate-regulation, unbilled revenue, pension and post-employment benefits, fair value of derivatives and fair value of assets and liabilities acquired in a business combination. Actual results may differ from these estimates.
APUC’s significant accounting policies and new accounting standards are discussed in Notes 1 and 2 in the annual audited consolidated financial statements, respectively. Management believes the following accounting policies involve the application of critical accounting estimates. Accordingly, these accounting estimates have been reviewed and discussed with the Audit Committee of the Board of Directors of APUC.
Consolidation and Variable Interest Entities
The Company uses judgment to assess whether its operations or investments represent variable interest entities ("VIEs"). In making these evaluations, management considers a) the sufficiency of the investment's equity at risk, b) the existence of a controlling financial interest, and c) the structure of any voting rights. In addition, management considers the specific facts and circumstances of each investment in a VIE when determining whether the Company is the primary beneficiary. The factors that management takes into consideration include the purpose and design of the VIE, the key decisions that affect its economic performance, whether the parties to the arrangements are related parties or defacto agents of the Company, and whether the Company has the power to direct the activities that would most significantly affect the economic performance of the VIE. Management's judgment is also required to determine whether the Company has the right to receive benefits or the obligation to absorb losses of the VIE. Based on the judgments made, the Company will consolidate the VIE if it determines that it is the primary beneficiary.
Estimated Useful Lives and Recoverability of Long-Lived Assets, Intangibles and Goodwill
The Company makes judgments a) to determine the recoverability of a development project, and the period over which the costs are capitalized during the development and construction of the project, b) to assess the nature of the costs to be capitalized, c) to distinguish individual components and major overhauls, and d) to determine the useful lives or unit-of-production over which assets are depreciated.
Depreciation rates on utility assets are subject to regulatory review and approval, and depreciation expense is recovered through rates set by ratemaking authorities. The recovery of those costs is dependent on the ratemaking process.
The carrying value of long-lived assets, including intangible assets and goodwill, is reviewed whenever events or changes in circumstances indicate that such carrying values may not be recoverable, and at least annually for goodwill. Some of the

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

factors APUC considers as indicators of impairment include a significant change in operational or financial performance, unexpected outcome from rate orders, natural disasters, energy pricing and changes in regulation. When such events or circumstances are present, the Company assesses whether the carrying value will be recovered through the expected future cash flows. If the facility includes goodwill, the fair value of the facility is compared to its carrying value. Both methodologies are sensitive to the forecasted cash flows and in particular energy prices, long-term growth rate and, discount rate for the fair value calculation.
In 2019 and 2018, Management assessed qualitative and quantitative factors for each of the reporting units that were allocated goodwill. No goodwill impairment provision was required.
Valuation of Deferred Tax Assets
In assessing the realization of deferred tax assets, management considers whether it is more likely than not that some portion or all of the deferred tax assets will not be realized and provides any necessary valuation allowances as required. Management evaluates the probability of realizing deferred tax assets by reviewing a forecast of future taxable income together with Management's intent and ability to implement tax planning strategies, if necessary, to realize deferred tax assets. Although at this time Management considers it more likely than not that it will have sufficient taxable income to realize the deferred tax assets, there can be no assurance that the Company will generate sufficient taxable income in the future to utilize these deferred tax assets. Management also assesses the ability to utilize tax attributes, including those in the form of carryforwards, for which the benefits have already been reflected in the financial statements.
Accounting for Rate Regulation
Accounting guidance for regulated operations provides that rate-regulated entities account for and report assets and liabilities consistent with the recovery of those incurred costs in rates if the rates established are designed to recover the costs of providing the regulated service and if the competitive environment makes it probable that such rates can be charged and collected. This accounting guidance is applied to the Regulated Services Group's operations.
Certain expenses and revenues subject to utility regulation or rate determination normally reflected in income are deferred on the balance sheet as regulatory assets or liabilities and are recognized in income as the related amounts are included in service rates and recovered from or refunded to customers. Regulatory assets and liabilities are recorded when it is probable that these items will be recovered or reflected in future rates. Determining probability requires significant judgment on the part of management and includes, but is not limited to, consideration of testimony presented in regulatory hearings, proposed regulatory decisions, final regulatory orders and industry practice. If events were to occur that would make the recovery of these assets and liabilities no longer probable, these regulatory assets and liabilities would be required to be written off or written down.
Unbilled Energy Revenues
Revenues related to natural gas, electricity and water delivery are generally recognized upon delivery to customers. The determination of customer billings is based on a systematic reading of meters throughout the month. At the end of each month, amounts of natural gas, energy or water provided to customers since the date of the last meter reading are estimated, and the corresponding unbilled revenue is recorded. Factors that can impact the estimate of unbilled energy include, but are not limited to, seasonal weather patterns compared to normal, total volumes supplied to the system, line losses, economic impacts, and composition of customer classes. Estimates are reversed in the following month and actual revenue is recorded based on subsequent meter readings.
Derivatives
APUC uses derivative instruments to manage exposure to changes in commodity prices, foreign exchange rates, and interest rates. Management’s judgment is required to determine if a transaction meets the definition of a derivative and, if it does, whether the normal purchases and sales exception applies or whether individual transactions qualify for hedge accounting treatment. Management’s judgment is also required to determine the fair value of derivative transactions. APUC determines the fair value of derivative instruments based on forward market prices in active markets obtained from external parties adjusted for nonperformance risk. A significant change in estimate could affect APUC’s results of operations if the hedging relationship was considered no longer effective.
Pension and Post-employment Benefits
The obligations and related costs of defined benefit pension and post-employment benefit plans are calculated using actuarial concepts, which include critical assumptions related to the discount rate, mortality rate, compensation increase, expected rate of return on plan assets and medical cost trend rates. These assumptions are important elements of expense and/or liability measurement and are updated on an annual basis, or upon the occurrence of significant events. The Company used

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

the new mortality improvement scale (MP-2019) recently released by the Society of Actuaries adjusted to reflect the 2019 Social Security Administration ultimate improvement rates.
Sensitivities
The sensitivities of key assumptions used in measuring accrued benefit obligations and benefit plan cost for 2019 are outlined in the following table. They are calculated independently of each other. Actual experience may result in changes in a number of assumptions simultaneously. The types of assumptions and method used to prepare the sensitivity analysis has not changed from previous periods and is consistent with the calculation of the retirement benefit obligations and net benefit plan cost recognized in the consolidated financial statements.

| 2019 Pension Plans |  | 2019 OPEB Plans
(all dollar amounts in $ millions) | Accrued Benefit Obligation |  | Net Periodic Pension Cost |  |  | Accumulated Postretirement Benefit Obligation |  | Net Periodic Postretirement Benefit Cost |
Discount Rate |  |  |  |  |
1% increase | (54.7 | ) | (2.8 | ) |  | (32.4 | ) | (1.6 | )
1% decrease | 67.6 |  | 5.2 |  |  | 42.0 |  | 2.8 |
Future compensation rate |  |  |  |  |
1% increase | 0.3 |  | 1.8 |  |  | — |  | — |
1% decrease | (0.3 | ) | (3.1 | ) |  | — |  | — |
Expected return on plan assets |  |  |  |  |
1% increase | — |  | (3.3 | ) |  | — |  | (1.2 | )
1% decrease | — |  | 3.3 |  |  | — |  | 1.2 |
Life expectancy |  |  |  |  |
10% increase | 32.8 |  | 3.6 |  |  | 20.3 |  | 2.4 |
10% decrease | (34.4 | ) | (4.3 | ) |  | (19.4 | ) | (2.0 | )
Health care trend |  |  |  |  |
1% increase | — |  | — |  |  | 39.2 |  | 4.4 |
1% decrease | — |  | — |  |  | (30.8 | ) | (2.6 | )

Business Combinations
The Company has completed a number of business combinations in the past few years. Management's judgment is required to estimate the purchase price, to identify and to fair value all assets and liabilities acquired. The determination of the fair value of assets and liabilities acquired is based upon management’s estimates and certain assumptions generally included in a present value calculation of the related cash flows.
Acquired assets and liabilities assumed that are subject to critical estimates include regulated property, plant and equipment, regulatory assets and liabilities, long-term debt and pension and OPEB obligations. The fair value of regulated property, plant and equipment is assessed using an income approach where the estimated cash flows of the assets are calculated using the approved tariff and discounted at the approved rate of return. The fair value of regulatory assets and liabilities considers the estimated timing of the recovery or refund to customers through the rate making process. The fair value of long-term debt is determined using a discounted cash flow method and current interest rates. The pension and OPEB obligations are valued by external actuaries using the guidelines of ASC 805, Business combinations.
Additional disclosure of APUC’s critical accounting estimates is also available on SEDAR at www.sedar.com, on EDGAR at www.sec.gov/edgar, and on the APUC website at www.AlgonquinPowerandUtilities.com.

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