EX-99.3 4 ex99_3.htm EXHIBIT 99.3 2018 Q4 MD&A

Exhibit 99.3
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, 2018. 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, 2018 and 2017. 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, 2018 and 2017 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 28, 2019.
Contents

Caution Concerning Forward-Looking Statements, Forward-Looking Information and non-GAAP Measures | 2
Overview and Business Strategy | 5
2018 Major Highlights | 6
2018 Fourth Quarter Results From Operations | 9
2018 Annual Results From Operations | 11
2018 Adjusted EBITDA Summary | 13
Liberty Utilities Group | 14
Liberty Power Group | 21
APUC: Corporate and Other Expenses | 26
Non-GAAP Financial Measures | 28
Corporate Development Activities | 31
Summary of Property, Plant, and Equipment Expenditures | 35
Liquidity and Capital Reserves | 37
Share-Based Compensation Plans | 39
Management of Capital Structure | 41
Related Party Transactions | 41
Enterprise Risk Management | 42
Quarterly Financial Information | 53
Summary Financial Information of Atlantica | 54
Disclosure Controls and Internal Controls Over Financial Reporting | 54
Critical Accounting Estimates and Policies | 55

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 are 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; ongoing and planned acquisitions, projects and initiatives, including expectations regarding costs, financing, results and completion dates; expectations regarding the Company’s corporate development activities and the results thereof; 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; contractual obligations and other commercial commitments; environmental liabilities; dividends to shareholders; expectations regarding the impact of tax reforms; credit ratings; anticipated growth and emerging opportunities in APUC’s target markets; accounting estimates; interest rates; currency exchange rates; and commodity prices. All forward-looking information is given pursuant to the “safe harbor” provisions of applicable securities legislation.
The forecasts and projections that make up the forward-looking information contained herein are based on certain factors or assumptions which include, but are not limited to: the receipt of applicable regulatory approvals and requested rate decisions; the absence of material adverse regulatory decisions being received and the expectation of regulatory stability; the absence of any material equipment breakdown or failure; availability of financing on commercially reasonable terms and the stability of credit ratings of the Corporation and its subsidiaries; the absence of unexpected material liabilities or uninsured losses; the continued availability of commodity supplies and stability of commodity prices; the absence of sustained interest rate increases or significant currency exchange rate fluctuations; the absence of significant operational disruptions or liability due to natural disasters or catastrophic events; the continued ability to maintain systems and facilities to ensure their continued performance; the absence of a severe and prolonged downturn in general economic, credit, social and market conditions; the successful and timely development and construction of new projects; the absence of material capital project or financing cost overruns; sufficient liquidity and capital resources; the continuation of observed weather patterns and trends; the absence of significant counterparty defaults; the continued competitiveness of electricity pricing when compared with alternative sources of energy; the realization of the anticipated benefits of the Corporation’s acquisitions and joint ventures; the absence of a material change in political conditions or public policies and directions by governments materially negatively affecting the Corporation; the ability to obtain and maintain licenses and permits; the absence of a material decrease in market energy prices; the absence of material disputes with taxation authorities or changes to applicable tax laws; continued maintenance of information technology infrastructure and the absence of a material breach of cyber security; favourable relations with external stakeholders; and favourable labour relations.
The forward-looking information contained herein is subject to risks, uncertainties and other factors that could cause actual results to differ materially from historical results or results anticipated by the forward-looking information. Factors which could cause results or events to differ materially from current expectations include, but are not limited to: changes in general economic, credit, social and market conditions; changes in customer energy usage patterns and energy demand; global climate change; the incurrence of environmental liabilities; natural disasters and other catastrophic events; the failure of information technology infrastructure and cybersecurity; the loss of key personnel and/or labour disruptions; seasonal fluctuations and variability in weather conditions and natural resource availability; reductions in demand for electricity, gas and water due to developments in technology; reliance on transmission systems owned and operated by third parties; issues arising with respect to land use rights and access to the Corporation’s facilities; critical equipment breakdown or failure; terrorist attacks; fluctuations in commodity prices; capital expenditures; reliance on subsidiaries; the incurrence of an uninsured loss; a credit rating downgrade; an increase in financing costs or limits on access to credit and capital markets; sustained increases in interest rates; currency exchange rate fluctuations; restricted financial flexibility due to covenants in existing credit agreements; an inability to refinance maturing debt on commercially reasonable terms; disputes with taxation authorities or changes to applicable tax laws; failure to identify, acquire or develop appropriate projects to maximize the value of PTC 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; loss of key customers; failure to realize the anticipated benefits of acquisitions or joint ventures; Atlantica or the Corporation’s joint venture with Abengoa acting in a manner contrary to the Corporation’s 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.

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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, changes in value of investments carried at fair value, and other typically non-recurring items as these are not reflective of the performance of the underlying business of APUC. The Non-cash accounting charge related to the revaluation of U.S. deferred income tax assets and liabilities as a result of implementation of the effects of 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.

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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 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.

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Overview and Business Strategy
APUC is incorporated under the Canada Business Corporations Act. APUC owns and operates a diversified portfolio of regulated and non-regulated generation, distribution, and transmission utility assets which are expected to deliver predictable earnings and cash flows. APUC seeks to maximize total shareholder value through real per share growth in earnings and cash flows to support a growing dividend and share price appreciation.
APUC’s current quarterly dividend to shareholders is $0.1282 per common share or $0.5128 per common share per annum. Based on exchange rates as at February 27, 2019, the quarterly dividend is equivalent to C$0.1685 per common share or C$0.6740 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 North American business units consisting of: the Liberty Utilities Group, which primarily owns and operates a portfolio of regulated electric, natural gas, water distribution and wastewater collection utility systems, and transmission operations; and the Liberty Power Group, which owns and operates a diversified portfolio of non-regulated renewable and thermal electric generation assets. APUC also owns a 41.5% beneficial stake in Atlantica Yield plc (NASDAQ: AY) (“Atlantica”), a company that acquires, owns and manages a diversified international portfolio of contracted renewable energy, power generation, electric transmission, and water assets. The investment in Atlantica is reported under the Liberty Power Group.
Liberty Utilities Group
The Liberty Utilities Group operates a diversified portfolio of regulated utility systems throughout the United States serving approximately 768,000 connections. The Liberty Utilities 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 Liberty Utilities Group seeks to deliver continued growth in earnings through accretive acquisitions of additional utility systems.
The Liberty Utilities Group's regulated electrical distribution utility systems and related generation assets are located in the States of California, New Hampshire, Missouri, Kansas, Oklahoma, and Arkansas which together serve approximately 266,000 electric connections. The group also owns and manages generating assets with a gross capacity of approximately 1.7 GW and has investments in a further approximately 0.3 GW of net generation capacity.
The Liberty Utilities Group's regulated natural gas distribution utility systems are located in the States of Georgia, Illinois, Iowa, Massachusetts, New Hampshire and Missouri which together serve approximately 338,000 natural gas connections.
The Liberty Utilities Group’s regulated water distribution and wastewater collection utility systems are located in the States of Arizona, Arkansas, California, Illinois, Missouri, and Texas which together serve approximately 164,000 connections.
Liberty Power Group
The Liberty Power Group generates and sells electrical energy produced by its diverse portfolio of non-regulated renewable power generation and clean power generation facilities located across North America. The Liberty Power Group seeks to deliver continuing growth through development of new greenfield power generation projects and accretive acquisitions of additional electrical energy generation facilities.
The Liberty Power Group owns and operates hydroelectric, wind, solar, and thermal facilities with a combined gross generating capacity of approximately 1.5 GW. Approximately 86% of the electrical output is sold pursuant to long term contractual arrangements which as of December 31, 2018 had a production-weighted average remaining contract life of approximately 14 years.
APUC has a 41.5% interest in 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.
Corporate Development
The Company's development activities for projects either owned directly by the Company or indirectly through AAGES entities are undertaken primarily by Abengoa-Algonquin Global Energy Solutions ("AAGES"), a joint venture with Abengoa S.A (MC: ABG) ("Abengoa"), an international infrastructure construction company. AAGES and its affiliates work with a global reach to identify, develop, and construct new renewable power generating facilities, power transmission lines, and water infrastructure assets. Once a project developed by AAGES has reached commercial operations ("COD"), APUC will work with AAGES to jointly determine whether it will be optimal for such project to be held by APUC, remain in AAGES, or be offered for sale to Atlantica or, in limited circumstances, another party.

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2018 Major Highlights
Corporate Highlights
Operating Results
APUC operating results relative to the same period last year are as follows:

|  | Three Months Ended December 31 |  |  | Twelve Months Ended December 31 |
(all dollar amounts in $ millions except per share information) |  | 2018 |  |  | 2017 |  |  | Change |  |  | 2018 |  |  | 2017 |  |  | Change |
Net earnings attributable to shareholders |  | $ | 44.0 |  |  | $ | 47.2 |  |  |  | (7 | )% |  | $ | 185.0 |  |  | $ | 149.5 |  |  |  | 24 | %
Adjusted Net Earnings1 |  | $ | 70.5 |  |  | $ | 67.0 |  |  |  | 5 | % |  | $ | 312.2 |  |  | $ | 225.0 |  |  |  | 39 | %
Adjusted EBITDA1 |  | $ | 196.9 |  |  | $ | 185.8 |  |  |  | 6 | % |  | $ | 803.3 |  |  | $ | 689.4 |  |  |  | 17 | %
Net earnings per common share |  | $ | 0.09 |  |  | $ | 0.11 |  |  |  | (18 | )% |  | $ | 0.38 |  |  | $ | 0.37 |  |  |  | 3 | %
Adjusted Net Earnings per common share1 |  | $ | 0.14 |  |  | $ | 0.16 |  |  |  | (13 | )% |  | $ | 0.66 |  |  | $ | 0.57 |  |  |  | 16 | %

1 | See Non-GAAP Financial Measures.

Declaration of 2019 First Quarter Dividend of $0.1282 (C$0.1685) per Common Share
APUC currently targets an industry leading annual growth in dividends payable to shareholders underpinned by increases in earnings and cashflow. 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 dividend payout ratio as a percentage of earnings per share and cash flow per share.
On February 28, 2019, APUC announced that the Board of APUC declared a first quarter 2019 dividend of $0.1282 per common share payable on April 15, 2019 to shareholders of record on March 29, 2019. Based on the Bank of Canada exchange rate on February 27, 2019, the Canadian dollar equivalent for the first quarter 2019 dividend is set at C$0.1685 per common share.
The previous four quarter equivalent Canadian dollar dividends per common share have been as follows:

|  |  | Q2 2018 |  |  |  | Q3 2018 |  |  |  | Q4 2018 |  |  |  | Q1 2019 |  |  | Total |
U.S. dollar dividend |  | $ | 0.1282 |  |  | $ | 0.1282 |  |  | $ | 0.1282 |  |  | $ | 0.1282 |  |  | $ | 0.5128 |
Canadian dollar equivalent |  | $ | 0.1648 |  |  | $ | 0.1673 |  |  | $ | 0.1679 |  |  | $ | 0.1685 |  |  | $ | 0.6685 |

Completed formation of AAGES Joint Venture with Abengoa
On March 9, 2018, APUC entered into an agreement to create AAGES, a joint venture with Abengoa S.A. (“Abengoa”), to identify, develop, and construct clean energy and water infrastructure assets.
Investment in Atlantica
In 2018, APUC purchased a 41.5% equity interest in Atlantica. Atlantica owns and manages a diversified international portfolio of contracted renewable energy, power generation, electric transmission, and water assets. The purchase was completed in two tranches.
On March 9, 2018, APUC acquired a 25% equity interest in Atlantica for a total purchase price of approximately $608 million, based on a price of $24.25 per ordinary share of Atlantica. On November 27, 2018, APUC purchased an additional 16.5% equity interest in Atlantica for a purchase price of approximately $345 million, based on a price of $20.90 per ordinary share of Atlantica.
The investment is expected to be immediately accretive to APUC’s earnings and cash flows. The Company has included within its 2018 operating results $39.3 million of dividends received from Atlantica.
Fitch Initiates First-Time Ratings to Algonquin Power & Utilities Corp. and Subsidiaries
On July 20, 2018, Fitch Ratings, Inc. (“Fitch”) assigned a BBB Long-Term Issuer Default Rating (“IDR”) and an F2 Short-Term IDR to APUC and Liberty Utilities Co. (“LUCo”), the parent company for the Liberty Utilities Group. Fitch assigned a BBB Long-Term IDR and an F3 Short-Term IDR to Algonquin Power Co (“APCo”), the parent company for the Liberty Power Group. The rating outlook for each entity is stable. Fitch also assigned a BBB+ rating to the senior unsecured debt issued by Liberty Utilities Finance GP1 (“Liberty Finance”), a special purpose financing entity of LUCo. See Treasury Risk Management- Downgrade in the Company’s Credit Rating Risk.

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DBRS Upgrades APUC and APCo Issuer Ratings to BBB with a Stable Trend
Subsequent to year end, DBRS Limited (“DBRS”) upgraded the issuer rating of APUC and APCo to BBB with a stable trend and APUC’s preferred share rating to Pfd-3. The APCo upgrade reflects the agency’s view of increased scale and a solid business risk profile resulting from long term contracted power assets. The APUC rating upgrade reflects the agency’s view of a significant improvement in the Company’s business risk profile following the acquisition and successful integration of The Empire District Electric Company (“Empire”) as well as strong cash flows underpinned by regulated operations and contracted power assets.
Corporate Financings Completed
C$444.4 Million Common Equity Financing
On April 24, 2018, APUC closed the sale of approximately 37.5 million of its common shares to certain institutional investors at a price of C$11.85 per share, for gross proceeds of approximately C$444.4 million. The proceeds of the offering were used to pay down existing indebtedness and to fund in part the purchase of the additional 16.5% interest in Atlantica.
Issuance of Fixed-to-Floating Subordinated Notes
On October 17, 2018, APUC issued $287.5 million of 60 (non-call 5) year fixed-to-floating 6.875% subordinated notes. The offering represents APUC’s inaugural entry into the U.S. public debt markets (see Long Term Debt).
C$172.5 Million Common Equity Financing
On December 20, 2018, APUC closed the sale of approximately 12.5 million of its common shares to certain institutional investors at a price of C$13.76 per share, for gross proceeds of approximately C$172.5 million. The proceeds of the offering will be used to partially finance the acquisition of Enbridge Gas New Brunswick Limited Partnership (“New Brunswick Gas”) (see Major Highlights - Liberty Utilities), and for general corporate purposes.
Change to U.S. Dollar Reporting
Effective the first quarter of 2018, APUC’s interim and annual consolidated financial statements are now reported in U.S. dollars.
Over 90% of APUC’s consolidated revenue, EBITDA and assets are derived from operations in the United States. In addition, APUC’s dividend is denominated in U.S. dollars and the Company’s common shares are listed on the New York Stock Exchange. The Company believes that the change in reporting to U.S. dollars provides improved information to investors and allow for better assessment of its results without the effects of the change in currency on 90% of its operations.
Liberty Utilities Group Highlights
Successful Rate Review Outcomes
A core strategy of the Liberty Utilities Group is to ensure an appropriate return is earned on the rate base at its various utility systems. During 2018 and 2019 year to date, the Liberty Utilities Group successfully completed several rate reviews representing a cumulative annualized revenue increase of approximately $24.5 million. In addition progress was made in advancing several regulatory mechanisms. In New Hampshire and Missouri the Public Utilities Commissions approved revenue decoupling as part of their orders.
Resolution with Regulators Regarding the Impacts of Tax Reform
On December 22, 2017, the Tax Cuts and Jobs Act ("U.S. Tax Reform") was signed into law which resulted in significant changes to U.S. tax law. Amongst other things, U.S. Tax Reform reduced the federal corporate income tax rates from 35% to 21%. The change in corporate tax rates has impacted regulatory revenue requirements of most public utilities, including the Liberty Utilities Group. Throughout the course of 2018, the Liberty Utilities Group obtained orders from the majority of its principal regulators covering approximately 93% of customers, resulting in the reduction of customer rates in connection with the reduction in tax rates. Collectively, the orders represent an annualized aggregate reduction in utility revenues of approximately $35 million, of which approximately $18 million has been realized in 2018.
Progress Made on Customer Savings Plan
In 2017, Empire proposed to its regulators in Missouri, Kansas, Oklahoma, and Arkansas a Customer Savings Plan which would phase out its Asbury Coal Generation Facility and develop additional wind generation in or near its service territory that will utilize all available Production Tax Credits. The plan calls for the development of up to 600 MW of sustainable, cost-effective wind power to serve the needs of electricity customers within the Liberty Utilities Group’s Midwest electric service territory and forecasts cost savings for customers of approximately $169 million and $325 million over a 20-year and 30-year period, respectively.
On July 11, 2018, Empire received an order from the Missouri Public Service Commission (“MPSC”) supporting various requests related to its proposed plan, which has allowed the Liberty Utilities Group to continue to pursue the development of up to 600 MW of wind power and recognizes that “millions of dollars of customer savings could be of considerable benefit to Empire’s customers and the entire state”.

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On October 18, 2018, and November 18, 2018, Empire filed with the MPSC a request for Certificates of Convenience and Necessity (“CCN”), in each case for 300 MW of the 600 MW contemplated as part of the initiative. A final hearing on the merits is scheduled for April 2019.
Acquisition of New Brunswick Gas
On December 4, 2018, the Liberty Utilities Group announced that it entered into an agreement to purchase New Brunswick Gas. 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 800 km of natural gas distribution pipeline. The total purchase price for the transaction is C$331 million, subject to customary adjustments. The transaction closing is expected in 2019, following regulatory approvals.
Acquisition of Ownership Interest in Wataynikaneyap Power Transmission Project
Subsequent to year-end on January 17, 2019, the Liberty Utilities 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 the area.
Liberty Power Group Highlights
Completion of the Great Bay Solar Project
On March 29, 2018, the Great Bay Solar Facility achieved COD. The facility consists of a 75 MW solar powered electric generating facility comprised of four sites located in Somerset County in southern Maryland. The Great Bay Solar Facility is the Liberty Power Group’s fourth solar generating facility and consists of 300,000 solar panels and is expected to generate 146.0 GW-hrs of energy per year, with all energy sold to the U.S. Government Services pursuant to a 10 year Power Purchase Agreement (“PPA”), with a 10 year extension option.
Completion of the Amherst Island Wind Project
On June 15, 2018, the Amherst Island Wind Facility achieved COD. The facility consists of a 75 MW wind powered electric generating facility located on Amherst Island near the village of Stella, approximately 15 kilometers southwest of Kingston, Ontario. The Amherst Island Wind Facility is the Liberty Power Group’s 12th wind powered electric generating facility and is comprised of 26 Siemens 3.2 MW turbines and is expected to generate approximately 235.0 GW-hrs of electrical energy annually, with all energy being sold to the Independent Electricity System Operator (“IESO”), formerly the Ontario Power Authority.
Issuance of Green Bonds
Subsequent to year-end on January 29, 2019, the Liberty Power 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 Liberty Power Group’s inaugural “green bond” offering (see Long Term Debt).

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2018 Fourth Quarter Results From Operations

Key Financial Information |  | Three Months Ended December 31 |
(all dollar amounts in $ millions except per share information) |  | 2018 |  |  | 2017 |
Revenue |  | $ | 419.9 |  |  | $ | 409.5 |
Net earnings attributable to shareholders |  |  | 44.0 |  |  |  | 47.2 |
Cash provided by operating activities |  |  | 168.6 |  |  |  | 116.0 |
Adjusted Net Earnings1 |  |  | 70.5 |  |  |  | 67.0 |
Adjusted EBITDA1 |  |  | 196.9 |  |  |  | 185.8 |
Adjusted Funds from Operations1 |  |  | 132.5 |  |  |  | 126.0 |
Dividends declared to common shareholders |  |  | 63.1 |  |  |  | 50.5 |
Weighted average number of common shares outstanding |  |  | 477,450,181 |  |  |  | 412,632,308 |
Per share |  |  |  |  |  |  |  |
Basic net earnings |  | $ | 0.09 |  |  | $ | 0.11 |
Diluted net earnings |  | $ | 0.09 |  |  | $ | 0.11 |
Adjusted Net Earnings1,2 |  | $ | 0.14 |  |  | $ | 0.16 |
Dividends declared to common shareholders |  | $ | 0.13 |  |  | $ | 0.12 |

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, 2018, APUC experienced an average exchange rate of Canadian to U.S. dollar of approximately 0.7568 as compared to 0.7865 in the same period in 2017. 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, 2018, APUC reported total revenue of $419.9 million as compared to $409.5 million during the same period in 2017, an increase of $10.4 million. The major factors resulting in the increase in APUC revenue in the three months ended December 31, 2018 as compared to the corresponding period in 2017 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 |  | $ | 409.5 |
LIBERTY UTILITIES GROUP |  |  |  |
Existing Facilities |  |  |  |
Electricity: Increase is primarily due to higher heating degree days, which resulted in higher consumption at the Empire Electric System. |  |  | 10.7 |
Gas: Increase is primarily due to higher consumption and pass through commodity costs at the Midstates, New England, Empire and EnergyNorth Gas Systems due to higher heating degree days. |  |  | 6.6 |
Water: Decrease is primarily due to lower consumption at the Arkansas Water System and lower phased-in revenue at the White Hall Water system. |  |  | (0.4 | )
Other |  |  | (0.2 | )
|  |  | 16.7 |
Rate Reviews |  |  |  |
Electricity: Implementation of lower rates at the Granite State and Empire Electric systems due to U.S. Tax reform, partially offset by rate increases at the Calpeco Electric System. |  |  | (4.4 | )
Gas: Implementation of new rates, partially offset by U.S. Tax Reform impact, primarily at Midstates and EnergyNorth Gas Systems. |  |  | 1.7 |
Water: Implementation of lower rates at the Arizona and Park Water Systems due to U.S. Tax Reform. |  |  | (0.7 | )
|  |  | (3.4 | )
LIBERTY POWER GROUP |  |  |  |
Existing Facilities |  |  |  |
Hydro: Increase is primarily due to higher production and favourable rates in the Western Region partially offset by unfavourable rates in the Maritime Region. |  |  | 0.9 |
Wind Canada: Decrease is primarily due to lower production. |  |  | (2.6 | )
Wind U.S.: Decrease is primarily due to lower production. |  |  | (3.4 | )
Solar Canada: Decrease is primarily due to lower production. |  |  | (0.1 | )
Solar U.S.: Decrease is primarily due to lower production. |  |  | (0.2 | )
Thermal: Increase is primarily due to higher production and an increase in capacity revenue at the Windsor Locks Thermal Facility earned through the second phase of a contract that began in 2018. |  |  | 1.2 |
Other |  |  | 0.4 |
|  |  | (3.8 | )
New Facilities |  |  |  |
Solar US: Great Bay Solar Facility achieved full COD in March 2018. |  |  | 1.7 |
|  |  | 1.7 |
Foreign Exchange |  |  | (0.8 | )
Current Period Revenue |  | $ | 419.9 |

A more detailed discussion of these factors is presented within the business unit analysis.
For the three months ended December 31, 2018, net earnings attributable to shareholders totaled $44.0 million as compared to $47.2 million during the same period in 2017, a decrease of $3.2 million or 6.8%. The decrease was due to a $10.2 million decrease in earnings from operating facilities, $46.0 million loss due to change in fair value of an investment carried at fair value, $6.9 million increase in interest expense, $0.3 million increase in administration charges and a $2.8 million decrease in gains from derivative instruments. These items were partially offset by a $9.9 million decrease in acquisition related costs, $5.4 million decrease in depreciation and amortization expenses, $0.6 million increase in foreign exchange gain, a $1.1 million decrease in pension and post-employment non-service costs, $17.5 million increase in interest, dividend, equity and other income primarily from the investment in Atlantica, $1.4 million increase in other gains, $0.2 million increase in net effect of non-controlling interests, and a $26.9 million decrease in income tax expense (tax explanations are discussed in APUC: Corporate and Other Expenses) as compared to the same period in 2017.
During the three months ended December 31, 2018, cash provided by operating activities totaled $168.6 million as compared to $116.0 million during the same period in 2017. During the three months ended December 31, 2018, Adjusted Funds from Operations totaled $132.5 million as compared to $126.0 million during the same period in 2017.

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

During the three months ended December 31, 2018, Adjusted EBITDA totaled $196.9 million as compared to $185.8 million during the same period in 2017, an increase of $11.1 million or 6.0%. 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).
2018 Annual Results From Operations

Key Financial Information |  | Twelve Months Ended December 31 |
(all dollar amounts in $ millions except per share information) |  | 2018 |  |  | 2017 |  |  | 2016 |
Revenue |  | $ | 1,647.4 |  |  | $ | 1,521.9 |  |  | $ | 823.0 |
Net earnings attributable to shareholders |  |  | 185.0 |  |  |  | 149.5 |  |  |  | 97.9 |
Cash provided by operating activities |  |  | 530.4 |  |  |  | 326.6 |  |  |  | 229.5 |
Adjusted Net Earnings1 |  |  | 312.2 |  |  |  | 225.0 |  |  |  | 121.4 |
Adjusted EBITDA1 |  |  | 803.3 |  |  |  | 689.4 |  |  |  | 358.9 |
Adjusted Funds from Operations1 |  |  | 554.1 |  |  |  | 477.1 |  |  |  | 267.9 |
Dividends declared to common shareholders |  |  | 235.4 |  |  |  | 185.9 |  |  |  | 113.2 |
Weighted average number of common shares outstanding |  |  | 461,818,023 |  |  |  | 382,323,434 |  |  |  | 271,832,430 |
Per share |  |  |  |  |  |  |  |  |  |  |  |
Basic net earnings |  | $ | 0.38 |  |  | $ | 0.37 |  |  | $ | 0.33 |
Diluted net earnings |  | $ | 0.38 |  |  | $ | 0.37 |  |  | $ | 0.33 |
Adjusted Net Earnings1,2 |  | $ | 0.66 |  |  | $ | 0.57 |  |  | $ | 0.42 |
Dividends declared to common shareholders |  | $ | 0.50 |  |  | $ | 0.47 |  |  | $ | 0.41 |
Total assets |  |  | 9,389.0 |  |  |  | 8,395.6 |  |  |  | 6,143.9 |
Long term debt3 |  |  | 3,337.3 |  |  |  | 3,080.5 |  |  |  | 3,181.7 |

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, 2018, APUC experienced an average exchange rate of Canadian to U.S. of approximately 0.7715 as compared to 0.7705 in the same period in 2017. 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, 2018, APUC reported total revenue of $1,647.4 million as compared to $1,521.9 million during the same period in 2017, an increase of $125.5 million or 8.2%. The major factors resulting in the increase in APUC revenue for the twelve months ended December 31, 2018 as compared to the corresponding period in 2017 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 |  | $ | 1,521.9 |
LIBERTY UTILITIES GROUP |  |  |  |
Existing Facilities |  |  |  |
Electricity: Increase is primarily due to higher heating degree days in the first & fourth quarters, and higher cooling degree days in the second & third quarters of the year, which resulted in higher consumption and pass through commodity costs at the Empire Electric System. |  |  | 71.4 |
Gas: Increase is primarily due to favourable weather resulting in higher consumption and higher pass through commodity costs at the Midstates, EnergyNorth, New England and Empire Gas Systems. |  |  | 48.1 |
Water: Decrease is primarily due to divestiture of the Mountain Water System from condemnation proceedings on June 22, 2017. |  |  | (10.4 | )
Other |  |  | (0.3 | )
|  |  | 108.8 |
Rate Reviews |  |  |  |
Electricity: Implementation of lower rates at the Empire Electric System due to U.S. Tax Reform, partially offset by rate increases at the Calpeco Electric System. |  |  | (3.7 | )
Gas: Implementation of new rates, net of U.S. Tax Reform impact, primarily at the Midstates and EnergyNorth Gas Systems. |  |  | 5.4 |
Water: Implementation of lower rates at the Arizona and Park Water Systems due to U.S. Tax Reform. |  |  | (1.3 | )
|  |  | 0.4 |
LIBERTY POWER GROUP |  |  |  |
Existing Facilities |  |  |  |
Hydro: Decrease is primarily due to lower production and the recognition of a bonus payment from Hydro Quebec in the prior year, partially offset by favourable rates in the Western Region. |  |  | (2.5 | )
Wind Canada: Decrease is primarily due to lower overall production. |  |  | (2.5 | )
Wind U.S.: Decrease is primarily due to lower production and unfavourable market rates at the Senate Wind Facility, partially offset by favourable market rates at the Shady Oaks, Sandy Ridge and Minonk Wind Facilities. |  |  | (5.5 | )
Solar Canada: Increase is primarily due to higher production. |  |  | 0.1 |
Thermal: Increase is primarily due to higher overall production as well as an increase in capacity revenue at the Windsor Locks Thermal Facility earned through the second phase of a contract that began in 2018. |  |  | 12.1 |
Other: Increase is primarily due to higher management fee from managed companies. |  |  | 0.8 |
|  |  | 2.5 |
New Facilities |  |  |  |
Wind U.S.: Acquisition of Deerfield Wind Facility in March 2017. |  |  | 6.0 |
Solar U.S.: Great Bay Solar Facility reached full COD in March 2018. |  |  | 7.6 |
|  |  | 13.6 |
Foreign Exchange |  |  | 0.2 |
Current Period Revenue |  | $ | 1,647.4 |

A more detailed discussion of these factors is presented within the business unit analysis.
For the twelve months ended December 31, 2018, net earnings attributable to shareholders totaled $185.0 million as compared to $149.5 million during the same period in 2017, an increase of $35.5 million. The increase was due to a $12.4 million increase in earnings from operating facilities, $43.9 million increase in interest, dividend, equity and other income received primarily from the investment in Atlantica, $47.0 million decrease in acquisition costs, $58.1 million increase in net effect of non-controlling interests, $0.4 million increase in foreign exchange gain, $3.7 million decrease in interest expense, a $5.1 million decrease in pension and post-employment non-service costs, and a $20.0 million decrease in income tax expense (tax explanations are discussed in APUC: Corporate and Other Expenses). These items were partially offset by a $138.0 million loss due to change in fair value of an investment carried at fair value, $3.1 million increase in administration charges, $9.5 million increase in depreciation and amortization expenses, $2.0 million increase in other losses, and a $2.5 million decrease on gains from derivative instruments.

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

During the twelve months ended December 31, 2018, cash provided by operating activities totaled $530.4 million as compared to $326.6 million during the same period in 2017. During the twelve months ended December 31, 2018, Adjusted Funds from Operations, a non-GAAP measure, totaled $554.1 million as compared to $477.1 million the same period in 2017, an increase of $77.0 million.
Adjusted EBITDA in the twelve months ended December 31, 2018 totaled $803.3 million as compared to $689.4 million during the same period in 2017, an increase of $113.9 million or 16.5%. 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).
2018 Adjusted EBITDA Summary
Adjusted EBITDA (see Non-GAAP Financial Measures) for the three months ended December 31, 2018 totaled $196.9 million as compared to $185.8 million during the same period in 2017, an increase of $11.1 million or 6.0%. Adjusted EBITDA for the twelve months ended December 31, 2018 totaled $803.3 million as compared to $689.4 million during the same period in 2017, an increase of $113.9 million or 16.5%. 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) |  | 2018 |  |  | 2017 |  |  | 2018 |  |  | 2017 |
Liberty Utilities Group Operating Profit |  | $ | 132.9 |  |  | $ | 144.4 |  |  | $ | 550.5 |  |  | $ | 544.2 |
Liberty Power Group Operating Profit |  |  | 78.7 |  |  |  | 55.7 |  |  |  | 303.6 |  |  |  | 192.8 |
Administrative Expenses |  |  | (15.0 | ) |  |  | (14.7 | ) |  |  | (52.7 | ) |  |  | (49.6 | )
Other Income & Expenses |  |  | 0.3 |  |  |  | 0.4 |  |  |  | 1.9 |  |  |  | 2.0 |
Total Algonquin Power & Utilities Adjusted EBITDA |  | $ | 196.9 |  |  | $ | 185.8 |  |  | $ | 803.3 |  |  | $ | 689.4 |
Change in Adjusted EBITDA ($) |  | $ | 11.1 |  |  |  |  |  |  | $ | 113.9 |  |  |  |  |
Change in Adjusted EBITDA (%) |  |  | 6.0 | % |  |  |  |  |  |  | 16.5 | % |  |  |  |

Change in Adjusted EBITDA |  | Three Months Ended December 31, 2018 |
(all dollar amounts in $ millions) |  | Utilities |  |  | Power |  |  | Corporate |  |  | Total |
Prior period balances |  | $ | 144.4 |  |  | $ | 55.7 |  |  | $ | (14.3 | ) |  | $ | 185.8 |
Existing Facilities |  |  | (8.1 | ) |  |  | 0.6 |  |  |  | (0.1 | ) |  |  | (7.6 | )
New Facilities |  |  | — |  |  |  | 23.0 |  |  |  | — |  |  |  | 23.0 |
Rate Reviews |  |  | (3.4 | ) |  |  | — |  |  |  | — |  |  |  | (3.4 | )
Foreign Exchange Impact |  |  | — |  |  |  | (0.6 | ) |  |  | — |  |  |  | (0.6 | )
Administrative Expenses |  |  | — |  |  |  | — |  |  |  | (0.3 | ) |  |  | (0.3 | )
Total change during the period |  | $ | (11.5 | ) |  | $ | 23.0 |  |  | $ | (0.4 | ) |  | $ | 11.1 |
Current period balances |  | $ | 132.9 |  |  | $ | 78.7 |  |  | $ | (14.7 | ) |  | $ | 196.9 |

Change in Adjusted EBITDA |  | Twelve Months Ended December 31, 2018 |
(all dollar amounts in $ millions) |  | Utilities |  |  | Power |  |  | Corporate |  |  | Total |
Prior period balances |  | $ | 544.2 |  |  | $ | 192.8 |  |  | $ | (47.6 | ) |  | $ | 689.4 |
Existing Facilities |  |  | 5.9 |  |  |  | 45.0 |  |  |  | (0.1 | ) |  |  | 50.8 |
New Facilities |  |  | — |  |  |  | 65.9 |  |  |  | — |  |  |  | 65.9 |
Rate Reviews |  |  | 0.4 |  |  |  | — |  |  |  | — |  |  |  | 0.4 |
Foreign Exchange Impact |  |  | — |  |  |  | (0.1 | ) |  |  | — |  |  |  | (0.1 | )
Administration Expenses |  |  | — |  |  |  | — |  |  |  | (3.1 | ) |  |  | (3.1 | )
Total change during the period |  | $ | 6.3 |  |  | $ | 110.8 |  |  | $ | (3.2 | ) |  | $ | 113.9 |
Current period balances |  | $ | 550.5 |  |  | $ | 303.6 |  |  | $ | (50.8 | ) |  | $ | 803.3 |

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

LIBERTY UTILITIES GROUP
The Liberty Utilities Group operates rate-regulated utilities that provide distribution services to approximately 768,000 connections in the natural gas, electric, water and wastewater sectors which is an increase of 6,000 connections as compared to the prior year resulting primarily from organic growth in the Liberty Utilities Group's service territories. The Liberty Utilities Group’s strategy is to grow its business organically and through business development activities while using prudent acquisition criteria. The Liberty Utilities Group believes that its business results are maximized by building constructive regulatory and customer relationships, and enhancing connections in the communities in which it operates.

|  | As at December 31 |
Utility System Type |  | 2018 |  |  | 2017 |
(all dollar amounts in $ millions) |  | Assets |  |  | Total Connections1 |  |  | Assets |  |  | Total Connections1 |
Electricity |  | $ | 2,578.7 |  |  |  | 266,000 |  |  | $ | 2,479.9 |  |  |  | 265,000 |
Natural Gas |  |  | 1,057.3 |  |  |  | 338,000 |  |  |  | 996.1 |  |  |  | 337,000 |
Water and Wastewater |  |  | 481.4 |  |  |  | 164,000 |  |  |  | 462.6 |  |  |  | 160,000 |
Total |  | $ | 4,117.4 |  |  |  | 768,000 |  |  | $ | 3,938.6 |  |  |  | 762,000 |
Accumulated Deferred Income Taxes Liability |  | $ | 438.4 |  |  |  |  |  |  | $ | 392.8 |  |  |  |  |

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

The Liberty Utilities Group aggregates the performance of its utility operations by utility system type – electricity, natural gas, and water and wastewater systems.
The electric distribution systems are comprised of regulated electrical distribution utility systems and serve approximately 266,000 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 338,000 connections located in the states of New Hampshire, Illinois, Iowa, Missouri, Georgia, and Massachusetts.
The water and wastewater distribution systems are comprised of regulated water distribution and wastewater collection utility systems and serve approximately 164,000 connections located in the states of Arkansas, Arizona, California, Illinois, Missouri and Texas.
2018 Annual Usage Results

Electric Distribution Systems |  | Three Months Ended December 31 |  |  | Twelve Months Ended December 31 |
|  | 2018 |  |  | 2017 |  |  | 2018 |  |  | 2017 |
Average Active Electric Connections For The Period |  |  |  |  |  |  |  |  |  |  |  |
Residential |  |  | 225,900 |  |  |  | 224,400 |  |  |  | 225,200 |  |  |  | 223,700 |
Commercial and industrial |  |  | 37,900 |  |  |  | 39,200 |  |  |  | 37,800 |  |  |  | 39,200 |
Total Average Active Electric Connections For The Period |  |  | 263,800 |  |  |  | 263,600 |  |  |  | 263,000 |  |  |  | 262,900 |
Customer Usage (GW-hrs) |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |
Residential |  |  | 611.2 |  |  |  | 571.7 |  |  |  | 2,535.1 |  |  |  | 2,320.1 |
Commercial and industrial |  |  | 971.2 |  |  |  | 882.3 |  |  |  | 3,988.9 |  |  |  | 3,523.1 |
Total Customer Usage (GW-hrs) |  |  | 1,582.4 |  |  |  | 1,454.0 |  |  |  | 6,524.0 |  |  |  | 5,843.2 |

For the three months ended December 31, 2018, the electric distribution systems’ usage totaled 1,582.4 GW-hrs as compared to 1,454.0 GW-hrs for the same period in 2017, an increase of 128.4 GW-hrs or 8.8%, primarily due to higher heating degree days at the Empire Electric System.
For the twelve months ended December 31, 2018, the electric distribution systems’ usage totaled 6,524.0 GW-hrs as compared to 5,843.2 GW-hrs for the same period in 2017, an increase of 680.8 GW-hrs or 11.7%. The increase is primarily due to higher heating degree days in the first and fourth quarters and higher cooling degree days in the second and third quarters at the Empire Electric System.

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

Natural Gas Distribution Systems |  | Three Months Ended December 31 |  |  | Twelve Months Ended December 31 |
|  | 2018 |  |  | 2017 |  |  | 2018 |  |  | 2017 |
Average Active Natural Gas Connections For The Period |  |  |  |  |  |  |  |  |  |  |  |
Residential |  |  | 288,900 |  |  |  | 286,700 |  |  |  | 288,700 |  |  |  | 287,100 |
Commercial and industrial |  |  | 31,700 |  |  |  | 31,700 |  |  |  | 31,700 |  |  |  | 31,700 |
Total Average Active Natural Gas Connections For The Period |  |  | 320,600 |  |  |  | 318,400 |  |  |  | 320,400 |  |  |  | 318,800 |
Customer Usage (MMBTU) |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |
Residential |  |  | 6,186,000 |  |  |  | 5,196,000 |  |  |  | 20,065,000 |  |  |  | 17,621,000 |
Commercial and industrial |  |  | 4,533,000 |  |  |  | 4,282,000 |  |  |  | 14,529,000 |  |  |  | 12,672,000 |
Total Customer Usage (MMBTU) |  |  | 10,719,000 |  |  |  | 9,478,000 |  |  |  | 34,594,000 |  |  |  | 30,293,000 |

For the three months ended December 31, 2018, usage at the natural gas distribution systems totaled 10,719,000 MMBTU as compared to 9,478,000 MMBTU during the same period in 2017, an increase of 1,241,000 MMBTU, or 13.1%. The increase is primarily due to higher heating degree days across all of the gas systems.
For the twelve months ended December 31, 2018, usage at the natural gas distribution systems totaled 34,594,000 MMBTU as compared to 30,293,000 MMBTU during the same period in 2017, an increase of 4,301,000 MMBTU or 14.2%. The increase is primarily due to higher heating degree days at the Midstates, Peach State and Empire Gas Systems.

Water and Wastewater Distribution Systems |  | Three Months Ended December 31 |  |  | Twelve Months Ended December 31 |
|  | 2018 |  |  | 2017 |  |  | 2018 |  |  | 2017 |
Average Active Connections For The Period |  |  |  |  |  |  |  |  |  |  |  |
Wastewater connections |  |  | 43,000 |  |  |  | 41,400 |  |  |  | 42,200 |  |  |  | 41,000 |
Water distribution connections |  |  | 113,200 |  |  |  | 111,800 |  |  |  | 112,800 |  |  |  | 121,400 |
Total Average Active Connections For The Period |  |  | 156,200 |  |  |  | 153,200 |  |  |  | 155,000 |  |  |  | 162,400 |
Gallons Provided |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |
Wastewater treated (millions of gallons) |  |  | 606 |  |  |  | 555 |  |  |  | 2,282 |  |  |  | 2,226 |
Water provided (millions of gallons) |  |  | 3,655 |  |  |  | 3,909 |  |  |  | 15,823 |  |  |  | 16,905 |
Total Gallons Provided |  |  | 4,261 |  |  |  | 4,464 |  |  |  | 18,105 |  |  |  | 19,131 |

During the three months ended December 31, 2018, the water and wastewater distribution systems provided approximately 3,655 million gallons of water to its customers and treated approximately 606 million gallons of wastewater as compared to 3,909 million gallons of water provided and 555 million gallons of wastewater treated during the same period in 2017.
During the twelve months ended December 31, 2018, the water and wastewater distribution systems provided approximately 15,823 million gallons of water to its customers and treated approximately 2,282 million gallons of wastewater as compared to 16,905 million gallons of water and 2,226 million gallons of wastewater during the same period in 2017. The decrease in the gallons of water provided to customers can be attributed to the disposition of the Mountain Water System in Montana in the second quarter of 2017. Excluding the Mountain Water System, the volumes of water provided to customers were relatively flat year-over-year.

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

2018 Liberty Utilities Group Operating Results

|  | Three Months Ended December 31 |  |  | Twelve Months Ended December 31 |
|  | 2018 |  |  | 2017 |  |  | 2018 |  |  | 2017 |
Revenue |  |  |  |  |  |  |  |  |  |  |  |
Utility electricity sales and distribution |  | $ | 193.2 |  |  | $ | 187.0 |  |  | $ | 831.2 |  |  | $ | 763.5 |
Less: cost of sales – electricity |  |  | (63.4 | ) |  |  | (51.6 | ) |  |  | (265.1 | ) |  |  | (222.4 | )
Net Utility Sales - electricity1 |  |  | 129.8 |  |  |  | 135.4 |  |  |  | 566.1 |  |  |  | 541.1 |
Utility natural gas sales and distribution |  |  | 115.5 |  |  |  | 108.0 |  |  |  | 395.5 |  |  |  | 344.2 |
Less: cost of sales – natural gas |  |  | (59.0 | ) |  |  | (53.1 | ) |  |  | (183.0 | ) |  |  | (141.7 | )
Net Utility Sales - natural gas1 |  |  | 56.5 |  |  |  | 54.9 |  |  |  | 212.5 |  |  |  | 202.5 |
Utility water distribution & wastewater treatment sales and distribution |  |  | 30.4 |  |  |  | 31.5 |  |  |  | 128.4 |  |  |  | 140.1 |
Less: cost of sales – water |  |  | (2.1 | ) |  |  | (2.4 | ) |  |  | (8.8 | ) |  |  | (9.5 | )
Net Utility Sales - water distribution & wastewater treatment1 |  |  | 28.3 |  |  |  | 29.1 |  |  |  | 119.6 |  |  |  | 130.6 |
Gas transportation |  |  | 10.4 |  |  |  | 9.6 |  |  |  | 33.4 |  |  |  | 31.2 |
Other revenue |  |  | 4.8 |  |  |  | 5.1 |  |  |  | 11.6 |  |  |  | 11.8 |
Net Utility Sales1 |  |  | 229.8 |  |  |  | 234.1 |  |  |  | 943.2 |  |  |  | 917.2 |
Operating expenses |  |  | (99.0 | ) |  |  | (92.4 | ) |  |  | (401.5 | ) |  |  | (383.4 | )
Other income |  |  | 1.5 |  |  |  | 1.4 |  |  |  | 5.6 |  |  |  | 4.2 |
HLBV2 |  |  | 0.6 |  |  |  | 1.3 |  |  |  | 3.2 |  |  |  | 6.2 |
Divisional Operating Profit1,3 |  | $ | 132.9 |  |  | $ | 144.4 |  |  | $ | 550.5 |  |  | $ | 544.2 |

1 | See Non-GAAP Financial Measures.

2 | HLBV income represents the value of net tax attributes earned by the Liberty Utilities Group in the period primarily from electricity generated 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 | 16

2018 Fourth Quarter Operating Results
For the three months ended December 31, 2018, the Liberty Utilities Group reported an operating profit (excluding corporate administration expenses) of $132.9 million as compared to $144.4 million for the comparable period in the prior year.
Highlights of the changes are summarized in the following table:

(all dollar amounts in $ millions) |  | Three Months Ended December 31 |
Prior Period Operating Profit |  | $ | 144.4 |
Existing Facilities |  |  |  |
Electricity: Decrease is primarily due to higher commodity costs combined with higher operating costs at the Empire and Granite State Electric Systems. |  |  | (10.3 | )
Gas: Increase is primarily due to operating cost savings at the New England Gas System. |  |  | 3.2 |
Water: Decrease is primarily due to increase in operating costs at the Arizona and Whitehall Water Systems. |  |  | (0.1 | )
Other |  |  | (0.9 | )
|  |  | (8.1 | )
Rate Reviews |  |  |  |
Electricity: Implementation of lower rates at the Granite State and Empire Electric Systems due to U.S. Tax reform, partially offset by rate increases at the Calpeco Electric System. |  |  | (4.4 | )
Gas: Implementation of new rates, net of U.S. Tax Reform impact, primarily at Midstates and EnergyNorth Gas Systems. |  |  | 1.7 |
Water: Implementation of lower rates at the Arizona and Park Water Systems due to U.S. Tax Reform. |  |  | (0.7 | )
|  |  | (3.4 | )
Current Period Divisional Operating Profit1 |  | $ | 132.9 |

1 | See Non-GAAP Financial Measures.

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

2018 Annual Operating Results
For the twelve months ended December 31, 2018, the Liberty Utilities Group reported an operating profit (excluding corporate administration expenses) of $550.5 million as compared to $544.2 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 |  | $ | 544.2 |
Existing Facilities |  |  |  |
Electricity: Increase is primarily due to higher heating degree days in the first and fourth quarters and higher cooling degree days in the second & third quarters of the year, which resulted in higher consumption at the Empire Electric System, partially offset by an increase in operating costs. |  |  | 8.9 |
Gas: Increase is primarily due to favourable weather resulting in higher consumption at the Empire Gas and New England Gas Systems, partially offset by an increase in operating costs at the EnergyNorth Gas System. |  |  | 2.5 |
Water: Decrease is primarily due to lower revenue resulting from the disposition of the Mountain Water System in Montana as well as higher operating costs. |  |  | (6.0 | )
Other |  |  | 0.5 |
|  |  | 5.9 |
Rate Reviews |  |  |  |
Electricity: Implementation of lower rates at the Empire Electric System due to U.S. Tax Reform, partially offset by rate increases at the Calpeco Electric System. |  |  | (3.7 | )
Gas: Implementation of new rates, net of U.S. Tax Reform impact, primarily at the Midstates and EnergyNorth Gas Systems. |  |  | 5.4 |
Water: Implementation of lower rates at the Arizona and Park Water Systems due to U.S. Tax Reform. |  |  | (1.3 | )
|  |  | 0.4 |
Current Period Divisional Operating Profit1 |  | $ | 550.5 |

1 | See Non-GAAP Financial Measures.

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

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

Utility | State | Regulatory Proceeding Type |  | Rate Request (millions) |  | Current Status
Completed Rate Reviews |  |  |  |  |  |
EnergyNorth Gas System | New Hampshire | General Rate Case (“GRC”) |  | $ | 19.5 |  | In April 2018, an Order was issued approving a full revenue decoupling mechanism and an immediate revenue increase of $13.1 million effective May 1, 2018 and the ability to collect an additional $0.4 million in the cost of gas filing. In total, this represents revenue increases of $13.5 million. Concurrent with the implementation of these new rates, the New Hampshire Public Utilities Commission (“NHPUC”) also ordered a reduction in rates of $2.4 million resulting from U.S. Tax Reform which will be reflected in EnergyNorth’s future rates effective May 1, 2018, bringing the net rate increase to $11.1 million.
New England Gas | Massachusetts | Gas System Enhancement Plan (“GSEP”) |  | $ | 5.8 |  | Final Order issued in April 2018 approving a $3.7 million rate increase effective May 1, 2018.
Missouri Gas System | Missouri | GRC |  | $ | 6.0 |  | Final Order issued in June 2018 approving a $4.6 million rate increase effective July 1, 2018 and a revenue decoupling mechanism for residential and small commercial customers.
Peach State Gas System | Georgia | GRAM |  | $ | 2.4 |  | On January 31, 2019, an Order was issued approving an increase in revenue of $2.4 million for rates effective February 1, 2019.
Empire Electric System | Missouri | Tax Cuts and Jobs Act of 2017 |  | $ | -17.8 |  | Prospective decrease in annual revenue of $17.8 million due to U.S. Tax Reform beginning August 30, 2018.
Various | Various | Various |  | $ | 4.8 |  | Rate reviews closed in 2018 with a combined approved rate increase of $3.0 million include: Park Water 2018 increase, Georgia Gas Rate Adjustment Mechanism, Missouri Water System, and Litchfield Park Water & Sewer.
Pending Rate Reviews |  |  |  |  |  |  |
CalPeco Electric | California | GRC |  | $ | 6.7 |  | On December 3, 2018, filed a three year application requesting a rate increase of $6.7 million for 2019 ($5.9 million for 2020 and $3.8 million for 2021).
Empire Electricity (Kansas System) | Kansas | GRC |  | $ | 2.5 |  | On December 7, 2018, filed an application requesting an incremental increase in revenue requirement of $2.5 million.
New England Natural Gas System | Massachusetts | GSEP |  | $ | 3.8 |  | On October 31, 2018, filed for an incremental increase in revenue requirement of $3.8 million for the 2019 GSEP.
Various | Various | Various |  | $ | 3.9 |  | Other pending rate review requests include: Woodmark/Tall Timbers Wastewater Systems ($1.6 million), Silverleaf Texas Water and Wastewater Systems ($1.3 million), and Apple Valley and Park Water Systems ($1.0 million).

Completed Rate Reviews
New Hampshire
On April 28, 2017, the Liberty Utilities Group filed a distribution rate application with the NHPUC, for rates to be effective May 1, 2018, seeking a total revenue increase of $19.5 million with approximately $14.5 million based on a test year ending December 31, 2016 plus a step increase of approximately $5.0 million. Temporary rates of $7.8 million to be effective July 1, 2017, and full revenue decoupling from the impacts of weather were requested. On June 30, 2017, the NHPUC approved temporary rates of $6.8 million effective July 1, 2017 to be in place until the end of the permanent rate case. On April 27, 2018, the NHPUC issued its Order approving a full revenue decoupling mechanism and an immediate revenue increase of $13.1 million effective May 1, 2018 and the ability to collect an additional $0.4 million in the cost of gas filing. In total, this represents revenue increases of $13.5 million (70% of the requested increase amount). Concurrent with the implementation of these new rates, the NHPUC has also ordered a reduction in rates of $2.4 million resulting from U.S. Tax Reform which will be reflected in the EnergyNorth Gas System’s future rates effective May 1, 2018, bringing the net rate increase to $11.1 million. The order also authorizes an ROE of 9.3% and an additional one-time, $1.3 million recoupment to be collected from customers to make whole the difference between the permanent rates and the temporary rates authorized on July 1, 2017. In May 2018, EnergyNorth filed a motion for rehearing to clarify the implementation date of the decoupling mechanism that was approved. In addition, the NHPUC resolved the impacts of tax reform through the rehearing instead of addressing it in a separate hearing. The net result was a one-time decrease in revenue of $0.3 million.

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

Massachusetts
On October 31, 2017, Liberty Utilities (New England Natural Gas Company) Corp. filed its 2018 GSEP application requesting recovery of $6.2 million for replacement of approximately 14 miles of eligible infrastructure. In March 2018, the revenue requirement was revised to $5.8 million. On April 30, 2018 an order was issued authorizing the recovery of $3.7 million. The revenue increase is not affected by U.S. Tax Reform but is expected to be addressed in the 2019 filing.
Missouri
On September 29, 2017, Liberty Utilities (Midstates Natural Gas) Corp. filed an application seeking a rate increase of $7.5 million for test year ending June 30, 2017 with proforma adjustments through to March 31, 2018. In April 2018, the revenue requirement request was revised to $6.0 million. An order was issued on June 6, 2018 authorizing an annual revenue increase of $4.6 million, a 9.8% ROE, and also incorporates the effects of U.S. Tax Reform. The order contemplates that new rates will go into effect on July 1, 2018. In addition, it adopts rate consolidation for the NEMO and WEMO districts, and allows the Liberty Utilities Group to adopt a Weather Normalization Adjustment Rider designed to adjust the Company’s rates for the impact of weather on customer usage.
On July 12, 2018, Empire received an order from the MPSC supporting various requests related to its proposed Customer Savings Plan, which calls for the development of up to 600 MW of sustainable, cost-effective wind power to serve the needs of electricity customers within the Liberty Utilities Group’s Midwest electric service territory. The order allows the Liberty Utilities Group to continue to pursue the development of up to 600 MW of wind and recognizes that “millions of dollars of customer savings could be of considerable benefit to Empire’s customers and the entire state”. In addition, regulatory proceedings in other jurisdictions will be completed as necessary. The Company has filed CCN applications with the MPSC for the North Fork Ridge, Kings Point and Neosho Ridge Wind Projects and a final hearing has been scheduled for April 2019. The Company has also filed a CCN application with the Kansas Corporation Commission for the gen-tie line associated with the Neosho Ridge Wind Project.

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

LIBERTY POWER GROUP

2018 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) |  | 2018 |  |  | 2017 |  |  | 2018 |  |  | 2017 |
Hydro Facilities: |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |
Maritime Region |  |  | 37.6 |  |  |  | 31.4 |  |  |  | 34.9 |  |  |  | 148.2 |  |  |  | 107.5 |  |  |  | 129.7 |
Quebec Region |  |  | 72.6 |  |  |  | 73.6 |  |  |  | 67.5 |  |  |  | 273.3 |  |  |  | 263.7 |  |  |  | 270.6 |
Ontario Region |  |  | 26.2 |  |  |  | 31.3 |  |  |  | 30.6 |  |  |  | 120.4 |  |  |  | 106.5 |  |  |  | 129.5 |
Western Region |  |  | 12.6 |  |  |  | 11.2 |  |  |  | 10.5 |  |  |  | 65.0 |  |  |  | 59.8 |  |  |  | 59.6 |
|  |  | 149.0 |  |  |  | 147.5 |  |  |  | 143.5 |  |  |  | 606.9 |  |  |  | 537.5 |  |  |  | 589.4 |
Wind Facilities: |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |
St. Damase |  |  | 22.7 |  |  |  | 22.2 |  |  |  | 24.0 |  |  |  | 76.9 |  |  |  | 78.8 |  |  |  | 74.3 |
St. Leon |  |  | 121.4 |  |  |  | 101.4 |  |  |  | 138.7 |  |  |  | 430.2 |  |  |  | 394.8 |  |  |  | 444.2 |
Red Lily1 |  |  | 24.1 |  |  |  | 20.0 |  |  |  | 29.2 |  |  |  | 88.5 |  |  |  | 81.3 |  |  |  | 91.6 |
Morse |  |  | 30.5 |  |  |  | 26.2 |  |  |  | 33.1 |  |  |  | 108.8 |  |  |  | 96.8 |  |  |  | 106.4 |
Amherst2 |  |  | 67.9 |  |  |  | 58.7 |  |  |  | — |  |  |  | 118.5 |  |  |  | 105.7 |  |  |  | — |
Sandy Ridge |  |  | 43.6 |  |  |  | 43.8 |  |  |  | 42.0 |  |  |  | 158.3 |  |  |  | 152.2 |  |  |  | 153.3 |
Minonk |  |  | 189.8 |  |  |  | 173.8 |  |  |  | 203.5 |  |  |  | 673.7 |  |  |  | 611.3 |  |  |  | 673.7 |
Senate |  |  | 140.0 |  |  |  | 125.2 |  |  |  | 126.6 |  |  |  | 520.4 |  |  |  | 484.9 |  |  |  | 492.8 |
Shady Oaks |  |  | 100.5 |  |  |  | 91.5 |  |  |  | 108.7 |  |  |  | 355.6 |  |  |  | 326.6 |  |  |  | 365.5 |
Odell |  |  | 238.0 |  |  |  | 199.9 |  |  |  | 244.6 |  |  |  | 831.8 |  |  |  | 759.4 |  |  |  | 807.2 |
Deerfield3 |  |  | 167.9 |  |  |  | 153.8 |  |  |  | 164.3 |  |  |  | 546.0 |  |  |  | 531.2 |  |  |  | 449.3 |
|  |  | 1,146.4 |  |  |  | 1,016.5 |  |  |  | 1,114.7 |  |  |  | 3,908.7 |  |  |  | 3,623.0 |  |  |  | 3,658.3 |
Solar Facilities: |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |
Cornwall |  |  | 2.2 |  |  |  | 1.8 |  |  |  | 2.1 |  |  |  | 14.7 |  |  |  | 14.5 |  |  |  | 14.4 |
Bakersfield |  |  | 13.0 |  |  |  | 9.5 |  |  |  | 12.7 |  |  |  | 77.2 |  |  |  | 70.0 |  |  |  | 70.5 |
Great Bay Solar4 |  |  | 25.7 |  |  |  | 26.4 |  |  |  | — |  |  |  | 115.6 |  |  |  | 110.6 |  |  |  | — |
|  |  | 40.9 |  |  |  | 37.7 |  |  |  | 14.8 |  |  |  | 207.5 |  |  |  | 195.1 |  |  |  | 84.9 |
Renewable Energy Performance |  |  | 1,336.3 |  |  |  | 1,201.7 |  |  |  | 1,273.0 |  |  |  | 4,723.1 |  |  |  | 4,355.6 |  |  |  | 4,332.6 |
Thermal Facilities: |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |
Windsor Locks |  |  | N/A | 5 |  |  | 46.1 |  |  |  | 31.8 |  |  |  | N/A | 5 |  |  | 154.7 |  |  |  | 122.0 |
Sanger |  |  | N/A | 5 |  |  | 11.3 |  |  |  | 33.5 |  |  |  | N/A | 5 |  |  | 146.4 |  |  |  | 86.0 |
|  |  |  |  |  |  | 57.4 |  |  |  | 65.3 |  |  |  |  |  |  |  | 301.1 |  |  |  | 208.0 |
Total Performance |  |  |  |  |  |  | 1,259.1 |  |  |  | 1,338.3 |  |  |  |  |  |  |  | 4,656.7 |  |  |  | 4,540.6 |

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 50% equity interest in the Amherst Wind Facility. The Amherst Wind Facility achieved COD on June 15, 2018 in accordance with the terms of the PPA, however, the facility was partially operational prior to that date. The production data includes all energy produced during the year.

3 | The Deerfield Wind Facility achieved COD on February 21, 2017 and was treated as an equity investment until March 14, 2017 at which time the Company acquired the remaining 50% ownership in the facility. The production noted above represents all production from the date of COD.

4 | 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 production data includes all energy produced during the year.

5 | Natural gas fired co-generation facility.

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

2018 Fourth Quarter Liberty Power Group Performance
For the three months ended December 31, 2018, the Liberty Power Group generated 1,259.1 GW-hrs of electricity as compared to 1,338.3 GW-hrs during the same period of 2017.
For the three months ended December 31, 2018, the hydro facilities generated 147.5 GW-hrs of electricity as compared to 143.5 GW-hrs produced in the same period in 2017, an increase of 2.8%. Electricity generated represented 99.0% of long-term average resources (“LTAR”) as compared to 92.8% during the same period in 2017. During the quarter, all regions except the Maritime Region were above their respective LTAR.
For the three months ended December 31, 2018, the wind facilities produced 1,016.5 GW-hrs of electricity as compared to 1,114.7 GW-hrs produced in the same period in 2017, a decrease of 8.8%. During the three months ended December 31, 2018, the wind facilities (excluding the Amherst Wind Facility) generated electricity equal to 88.8% of LTAR as compared to 103.3% during the same period in 2017 primarily due to lower wind resource.
For the three months ended December 31, 2018, the solar facilities generated 37.7 GW-hrs of electricity as compared to 14.8 GW-hrs of electricity in the same period in 2017, an increase of 154.7%. 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 (excluding the Great Bay Solar Facility) production was 25.7% below its LTAR as compared to 2.6% below in the same period in 2017 primarily due to lower irradiance.
For the three months ended December 31, 2018, the thermal facilities generated 57.4 GW-hrs of electricity as compared to 65.3 GW-hrs of electricity during the same period in 2017. During the same period, the Windsor Locks Thermal Facility generated 145.7 billion lbs of steam as compared to 136.9 billion lbs of steam during the same period in 2017.
2018 Annual Liberty Power Group Performance
For the twelve months ended December 31, 2018, the Liberty Power Group generated 4,656.7 GW-hrs of electricity as compared to 4,540.6 GW-hrs during the same period of 2017.
For the twelve months ended December 31, 2018, the hydro facilities generated 537.5 GW-hrs of electricity as compared to 589.4 GW-hrs produced in the same period in 2017, a decrease of 8.8%. Electricity generated represented 88.6% of LTAR as compared to 94.7% during the same period in 2017. The decrease is primarily due to reduced hydrology in the Maritime and Ontario Regions.
For the twelve months ended December 31, 2018, the wind facilities produced 3,623.0 GW-hrs of electricity as compared to 3,658.3 GW-hrs produced in the same period in 2017, a decrease of 1.0%. During the twelve months ended December 31, 2018, the wind facilities generated electricity equal to 92.7% of LTAR as compared to 98.7% during the same period in 2017. The decrease in production was partially offset by higher production at the St. Damase Wind Facility as well as the incremental electricity generated at the Deerfield and Amherst Wind Facilities which achieved COD on February 21, 2017 and June 15, 2018, respectively.
For the twelve months ended December 31, 2018, the solar facilities generated 195.1 GW-hrs of electricity as compared to 84.9 GW-hrs of electricity produced in the same period in 2017, an increase of 129.8%. 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 (excluding the Great Bay Solar Facility) production was 8.1% below its LTAR as compared to 7.6% below in the same period in 2017.
For the twelve months ended December 31, 2018, the thermal facilities generated 301.1 GW-hrs of electricity as compared to 208.0 GW-hrs of electricity during the same period in 2017. During the same period, the Windsor Locks Thermal Facility generated 566.9 billion lbs of steam as compared to 559.1 billion lbs of steam during the same period in 2017.

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

2018 Liberty Power Group Operating Results |
|  | Three Months Ended December 31 |  |  | Twelve Months Ended December 31 |
(all dollar amounts in $ millions) |  | 2018 |  |  | 2017 |  |  | 2018 |  |  | 2017 |
Revenue1 |  |  |  |  |  |  |  |  |  |  |  |
Hydro |  | $ | 11.7 |  |  | $ | 11.0 |  |  | $ | 42.6 |  |  | $ | 44.7 |
Wind |  |  | 37.7 |  |  |  | 42.5 |  |  |  | 133.5 |  |  |  | 132.1 |
Solar |  |  | 2.8 |  |  |  | 1.6 |  |  |  | 17.2 |  |  |  | 10.8 |
Thermal |  |  | 10.2 |  |  |  | 8.8 |  |  |  | 42.1 |  |  |  | 30.0 |
Total Revenue |  | $ | 62.4 |  |  | $ | 63.9 |  |  | $ | 235.4 |  |  | $ | 217.6 |
Less: |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |
Cost of Sales - Energy2 |  |  | (1.4 | ) |  |  | (1.5 | ) |  |  | (5.5 | ) |  |  | (5.1 | )
Cost of Sales - Thermal |  |  | (5.1 | ) |  |  | (4.6 | ) |  |  | (21.7 | ) |  |  | (14.5 | )
Realized gain/(loss) on hedges3 |  |  | 0.1 |  |  |  | — |  |  |  | 0.1 |  |  |  | (0.7 | )
Net Energy Sales8 |  | $ | 56.0 |  |  | $ | 57.8 |  |  | $ | 208.3 |  |  | $ | 197.3 |
Renewable Energy Credits (“REC”)4 |  |  | 2.7 |  |  |  | 4.3 |  |  |  | 11.0 |  |  |  | 13.2 |
Other Revenue |  |  | 0.4 |  |  |  | 0.1 |  |  |  | 0.9 |  |  |  | 0.4 |
Total Net Revenue |  | $ | 59.1 |  |  | $ | 62.2 |  |  | $ | 220.2 |  |  | $ | 210.9 |
Expenses & Other Income |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |
Operating expenses |  |  | (13.2 | ) |  |  | (17.3 | ) |  |  | (71.0 | ) |  |  | (66.9 | )
Interest, dividend, equity and other income5 |  |  | 18.3 |  |  |  | 0.9 |  |  |  | 45.7 |  |  |  | 2.9 |
HLBV income6 |  |  | 14.5 |  |  |  | 9.9 |  |  |  | 108.7 |  |  |  | 45.9 |
Divisional Operating Profit7,8 |  | $ | 78.7 |  |  | $ | 55.7 |  |  | $ | 303.6 |  |  | $ | 192.8 |

1 | While most of the Liberty Power Group’s PPAs include annual rate increases, a change to the weighted average production levels resulting from higher average production from facilities that earn lower energy rates can result in a lower weighted average energy rate earned by the division as compared to the same period in the prior year.

2 | Cost of Sales - Energy consists of energy purchases in the Maritime Region to manage the energy sales from the Tinker Hydro Facility which is sold to retail and industrial customers under multi-year contracts.

3 | See Note 23(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 of electricity was generated from an eligible energy source.

5 | Includes dividends received from Atlantica of which APUC owns approximately 41.5% of the common shares (see Note 8 in the annual audited consolidated financial statements).

6 | HLBV income represents the value of net tax attributes earned by the Liberty Power Group in the period primarily from electricity generated by certain of its U.S. wind power and U.S. solar generation facilities.

7 | Certain prior year items have been reclassified to conform to current year presentation.

8 | See Non-GAAP Financial Measures.

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

2018 Fourth Quarter Operating Results
For the three months ended December 31, 2018, the Liberty Power Group’s facilities generated $78.7 million of operating profit as compared to $55.7 million during the same period in 2017, which represents an increase of $23.0 million or 41.3%, 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 |  | $ | 55.7 |
Existing Facilities |  |  |  |
Hydro: Increase is primarily due to higher production and favourable rates in the Western Region, partially offset by unfavourable rates in the Maritime Region. |  |  | 0.9 |
Wind Canada: Decrease is primarily due to lower production. |  |  | (2.5 | )
Wind U.S.: Decrease is primarily due to lower production, partially offset by higher HLBV income at the Deerfield Wind Facility. |  |  | (1.7 | )
Solar Canada: Decrease is primarily due to lower production. |  |  | (0.1 | )
Solar U.S.: Decrease is primarily due to a change in HLBV income assumptions as a result of U.S. Tax Reform. |  |  | (1.1 | )
Thermal: Increase is primarily due to higher overall production as well as an increase in capacity revenue at the Windsor Locks Thermal Facility earned through the second phase of a contract that began in 2018, partially offset by an increase in fuel costs. |  |  | 0.3 |
Other: Increase is primarily due higher dividend and equity income. |  |  | 4.8 |
|  |  | 0.6 |
New Facilities and Investments |  |  |  |
Solar U.S.: Great Bay Solar reached full COD in March 2018. |  |  | 4.7 |
Wind Canada: Amherst Island Wind Facility interest and equity income received as it achieved COD in June 2018. |  |  | 2.7 |
Atlantica & AAGES: Dividends from Atlantica, net of AAGES equity loss. |  |  | 15.6 |
|  |  | 23.0 |
Foreign Exchange |  |  | (0.6 | )
Current Period Divisional Operating Profit1 |  | $ | 78.7 |

1 | See Non-GAAP Financial Measures.

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

2018 Annual Operating Results
For the twelve months ended December 31, 2018, the Liberty Power Group’s facilities generated $303.6 million of operating profit as compared to $192.8 million during the same period in 2017, which represents an increase of $110.8 million or 57.5%, excluding corporate administration expenses.
Highlights of the changes are summarized in the following table:

(all dollar amounts in $ millions) |  | Twelve Months Ended December 31 |
Prior Period Operating Profit |  | $ | 192.8 |
Existing Facilities |  |  |  |
Hydro: Decrease is primarily due to lower production and the recognition of a bonus payment from Hydro Quebec in the prior year, partially offset by favourable rates in the Western Region. |  |  | (2.5 | )
Wind Canada: Decrease is primarily due to lower overall production |  |  | (2.6 | )
Wind U.S.: Increase is primarily due to HLBV income acceleration resulting from U.S. Tax Reform1, partially offset by lower production. |  |  | 41.6 |
Solar Canada: Increase is primarily due to higher production. |  |  | 0.1 |
Thermal: Increase is primarily due to higher overall production as well as an increase in capacity revenue at the Windsor Locks Thermal Facility earned through the second phase of a contract that began in 2018, partially offset by an increase in fuel costs. |  |  | 3.5 |
Other: Increase is primarily due higher dividend and equity income. |  |  | 4.9 |
|  |  | 45.0 |
New Facilities and Investments |  |  |  |
Wind U.S.: Acquisition of Deerfield Wind Facility in March 2017. |  |  | 13.5 |
Solar U.S.: Great Bay Solar achieved full COD in March 2018. |  |  | 10.7 |
Wind Canada: Amherst Island Wind Facility interest and equity income received as it achieved COD in June 2018. |  |  | 4.3 |
Atlantica & AAGES: Dividends from Atlantica, net of AAGES equity loss. |  |  | 37.4 |
|  |  | 65.9 |
Foreign Exchange |  |  | (0.1 | )
Current Period Divisional Operating Profit2 |  | $ | 303.6 |

1 | As a result of U.S. Tax Reform, the differential membership interests associated with the Company’s renewable energy projects in the U.S. that utilized tax equity were remeasured. This remeasurement resulted in an acceleration of income associated with HLBV in the amount of $55.9 million for the existing Wind U.S. and Solar U.S. facilities at the Liberty Power Group. Over the remaining life of existing tax equity structures of APUC, U.S. Tax Reform on balance has not materially affected, either positively or negatively, the economic benefits of the underlying tax equity structures in total.

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) |  | 2018 |  |  | 2017 |  |  | 2018 |  |  | 2017 |
Corporate and other expenses: |  |  |  |  |  |  |  |  |  |  |  |
Administrative expenses |  | $ | 15.0 |  |  | $ | 14.7 |  |  | $ | 52.7 |  |  | $ | 49.6 |
Loss (gain) on foreign exchange |  |  | 0.7 |  |  |  | 1.3 |  |  |  | (0.1 | ) |  |  | 0.3 |
Interest expense on convertible debentures and costs related to acquisition financing |  |  | — |  |  |  | — |  |  |  | — |  |  |  | 13.4 |
Interest expense |  |  | 40.3 |  |  |  | 33.4 |  |  |  | 152.1 |  |  |  | 142.4 |
Depreciation and amortization |  |  | 63.8 |  |  |  | 69.2 |  |  |  | 260.8 |  |  |  | 251.3 |
Change in value of investment carried at fair value |  |  | 46.0 |  |  |  | — |  |  |  | 138.0 |  |  |  | — |
Interest, dividend, equity, and other loss (income)1 |  |  | (0.4 | ) |  |  | (0.5 | ) |  |  | (1.8 | ) |  |  | (2.2 | )
Pension and post-employment non-service costs2 |  |  | 1.4 |  |  |  | 2.5 |  |  |  | 3.9 |  |  |  | 9.0 |
Other losses |  |  | 2.3 |  |  |  | 3.7 |  |  |  | 2.7 |  |  |  | 0.7 |
Acquisition-related costs, net |  |  | (8.9 | ) |  |  | 1.0 |  |  |  | 0.7 |  |  |  | 47.7 |
Loss (gain) on derivative financial instruments |  |  | (0.3 | ) |  |  | (3.1 | ) |  |  | 0.6 |  |  |  | (1.9 | )
Income tax expense |  |  | 2.8 |  |  |  | 29.7 |  |  |  | 53.4 |  |  |  | 73.4 |

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

2 | Pension amounts previously noted as part of operating expenses. See Note 10 in the annual audited consolidated financial statements for further details.

2018 Fourth Quarter Corporate and Other Expenses
During the three months ended December 31, 2018, administrative expenses totaled $15.0 million as compared to $14.7 million in the same period in 2017.
For the three months ended December 31, 2018, interest expense totaled $40.3 million as compared to $33.4 million in the same period in 2017. The increase is primarily due to drawings under the Corporate Term Facility and issuance of Fixed-to-Floating Subordinated Notes in October 2018, partially offset by debt maturities.
For the three months ended December 31, 2018, depreciation expense totaled $63.8 million as compared to $69.2 million in the same period in 2017. The decrease is primarily due to a one-time adjustment due to regulatory proceedings.
For the three months ended December 31, 2018, change in investment carried at fair value totaled $46.0 million as compared to $nil in 2017. The 2018 change in fair value reflects an unrealized loss related to the investment in Atlantica (see Note 8 in the annual audited consolidated financial statements).
For the three months ended December 31, 2018, pension and post-employment non-service costs totaled $1.4 million as compared to $2.5 million in 2017.
For the three months ended December 31, 2018, other losses were $2.3 million as compared to $3.7 million in the same period in 2017. The loss in 2018 mainly relates to the write down of notes receivables and costs from condemnation proceedings. The loss in 2017 was primarily attributable to an increase in regulatory liabilities in the LPSCo Water System resulting from ongoing regulatory proceedings.
For the three months ended December 31, 2018, acquisition related cost recovery totaled $8.9 million as compared to an expense of $1.0 million in 2017. The decrease is primarily due to a settlement related to the Shady Oaks Wind Facility acquisition.
For the three months ended December 31, 2018, gains on derivative financial instruments totaled $0.3 million as compared to $3.1 million in the same period in 2017. The gains in 2017 were primarily driven by mark-to-market gains on commodity derivatives.
For the three months ended December 31, 2018, an income tax expense of $2.8 million was recorded as compared to an income tax expense of $29.7 million during the same period in 2017. The decrease in income tax expense is primarily due to U.S. Tax Reform (see U.S. Tax Reform for additional information).

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

2018 Annual Corporate and Other Expenses
During the twelve months ended December 31, 2018, administrative expenses totaled $52.7 million as compared to $49.6 million in the same period in 2017. 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, 2018, interest expense on convertible debentures and bridge financing totaled $nil as compared to $13.4 million in the same period in 2017. The 2017 expense related to non-recurring financing costs related to the acquisition of Empire, as well as interest expense on convertible debentures before conversion to common shares in the first quarter of 2017.
For the twelve months ended December 31, 2018, interest expense totaled $152.1 million as compared to $142.4 million in the same period in 2017. The increase is primarily due to drawings under the Corporate Term Facility and issuance of Fixed-to-Floating Subordinated Notes in October 2018, partially offset by debt maturities.
For the twelve months ended December 31, 2018, depreciation expense totaled $260.8 million as compared to $251.3 million in the same period in 2017. The increase is primarily due to an increase in property, plant and equipment.
For the twelve months ended December 31, 2018, change in investment carried at fair value totaled $138.0 million as compared to $nil in the same period in 2017. The 2018 change in fair value reflects an unrealized loss related to the investment in Atlantica (see Note 8 in the annual audited consolidated financial statements).
For the twelve months ended December 31, 2018, pension and post-employment non-service costs totaled $3.9 million as compared to $9.0 million in the same period in 2017. The decrease is primarily due to a higher return on plan assets in 2018.
For the twelve months ended December 31, 2018, other losses were $2.7 million as compared to a loss of $0.7 million in the same period in 2017. The loss in 2018 mainly relates to the write down of notes receivables and costs from condemnation proceedings. The prior period loss is primarily related to the write-off of rate review expenses for several water utilities, partially offset by the disposition of the Mountain Water utility.
For the twelve months ended December 31, 2018, acquisition-related costs totaled $0.7 million as compared to $47.7 million in the same period in 2017. The costs in 2018 primarily related to the investment in Atlantica, partially offset by a settlement related to the Shady Oaks Wind Facility acquisition. The costs in 2017 primarily related to the acquisition of Empire.
For the twelve months ended December 31, 2018, the loss on derivative financial instruments totaled $0.6 million as compared to a gain of $1.9 million in the same period in 2017. The gain in 2017 was primarily due to mark-to-market gains on commodity derivatives. The loss in 2018 is primarily due to the ineffective portion related to the extension of the Liberty Power Group’s interest rate hedge on expected debt financing.
An income tax expense of $53.4 million was recorded in the twelve months ended December 31, 2018 as compared to an income tax expense of $73.4 million during the same period in 2017. The decrease in income tax expense is primarily due to U.S. Tax Reform (see U.S. Tax Reform for additional information).
U.S. Tax Reform
On December 22, 2017, H.R. 1, the Tax Cuts and Jobs Act (“U.S. Tax Reform” or the “Act”), was signed into law which among other things, reduced the U.S. federal corporate income tax rate from 35% to 21% effective January 1, 2018. As a result, in the fourth quarter of 2017, the Company was required to revalue its U.S. deferred income tax assets and liabilities based on the new tax rate. This remeasurement resulted in a non-cash accounting charge of $17.1 million which was recorded in the Company’s 2017 consolidated statement of operations.
In 2018, the Company completed its remeasurement of deferred income tax assets and liabilities as permitted under the measurement period outlined under SEC Staff Accounting Bulletin 118, Income Tax Accounting Implications of the Tax Cuts and Jobs Act (“SAB 118”). The final adjustments related to the implementation of U.S. Tax Reform resulted in a non-cash accounting benefit of $18.4 million which was recorded in the Company’s 2018 consolidated statement of operations.

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) |  | 2018 |  |  | 2017 |  |  | 2018 |  |  | 2017 |
Net earnings attributable to shareholders |  | $ | 44.0 |  |  | $ | 47.2 |  |  | $ | 185.0 |  |  | $ | 149.5 |
Add (deduct): |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |
Net earnings attributable to the non-controlling interest, exclusive of HLBV |  |  | 3.4 |  |  |  | 0.6 |  |  |  | 4.8 |  |  |  | 2.4 |
Income tax expense |  |  | 2.8 |  |  |  | 29.7 |  |  |  | 53.4 |  |  |  | 73.4 |
Interest expense on convertible debentures and costs related to acquisition financing |  |  | — |  |  |  | — |  |  |  | — |  |  |  | 13.4 |
Interest expense on long-term debt and others |  |  | 40.3 |  |  |  | 33.3 |  |  |  | 152.1 |  |  |  | 142.4 |
Other losses |  |  | 2.3 |  |  |  | 3.8 |  |  |  | 2.7 |  |  |  | 0.7 |
Acquisition-related costs |  |  | (8.9 | ) |  |  | 1.0 |  |  |  | 0.7 |  |  |  | 47.7 |
Pension and post-employment non-service costs1 |  |  | 1.4 |  |  |  | 2.5 |  |  |  | 3.9 |  |  |  | 9.0 |
Change in value of investment in Atlantica carried at fair value |  |  | 46.0 |  |  |  | — |  |  |  | 138.0 |  |  |  | — |
Costs related to tax equity financing |  |  | 1.3 |  |  |  | 0.4 |  |  |  | 1.3 |  |  |  | 1.8 |
Loss (gain) on derivative financial instruments |  |  | (0.3 | ) |  |  | (3.1 | ) |  |  | 0.6 |  |  |  | (1.9 | )
Realized (loss) gain on energy derivative contracts |  |  | 0.1 |  |  |  | — |  |  |  | 0.1 |  |  |  | (0.6 | )
Loss (gain) on foreign exchange |  |  | 0.7 |  |  |  | 1.2 |  |  |  | (0.1 | ) |  |  | 0.3 |
Depreciation and amortization |  |  | 63.8 |  |  |  | 69.2 |  |  |  | 260.8 |  |  |  | 251.3 |
Adjusted EBITDA |  | $ | 196.9 |  |  | $ | 185.8 |  |  | $ | 803.3 |  |  | $ | 689.4 |

1 | As a result of adoption of ASU 2017-07 certain components of net benefit pension costs are considered non-service costs and are now classified outside of operating income (see Note 2(a) in the annual audited consolidated financial statements).

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, 2018 amounted to $13.8 million and $110.7 million as compared to $11.3 million and $52.1 million during the same period in 2017. 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 | 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) |  | 2018 |  |  | 2017 |  |  | 2018 |  |  | 2017 |
Net earnings attributable to shareholders |  | $ | 44.0 |  |  | $ | 47.2 |  |  | $ | 185.0 |  |  | $ | 149.5 |
Add (deduct): |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |
Loss (gain) on derivative financial instruments |  |  | (0.3 | ) |  |  | (3.1 | ) |  |  | 0.6 |  |  |  | (1.9 | )
Realized (loss) gain on energy derivative contracts |  |  | 0.1 |  |  |  | — |  |  |  | 0.1 |  |  |  | (0.6 | )
Loss (gain) on long-lived assets, net |  |  | 1.9 |  |  |  | 1.2 |  |  |  | 0.8 |  |  |  | (1.8 | )
Loss (gain) on foreign exchange |  |  | 0.7 |  |  |  | 1.2 |  |  |  | (0.1 | ) |  |  | 0.3 |
Interest expense on convertible debentures and costs related to acquisition financing |  |  | — |  |  |  | — |  |  |  | — |  |  |  | 13.4 |
Acquisition-related costs |  |  | (8.9 | ) |  |  | 1.0 |  |  |  | 0.7 |  |  |  | 47.7 |
Change in value of investment in Atlantica carried at fair value |  |  | 46.0 |  |  |  | — |  |  |  | 138.0 |  |  |  | — |
Costs related to tax equity financing |  |  | 1.3 |  |  |  | 0.4 |  |  |  | 1.3 |  |  |  | 1.8 |
Other adjustments |  |  | — |  |  |  | 2.5 |  |  |  | — |  |  |  | 2.5 |
U.S. Tax Reform and related deferred tax adjustments1 |  |  | (18.4 | ) |  |  | 17.1 |  |  |  | (18.4 | ) |  |  | 17.1 |
Adjustment for taxes related to above |  |  | 4.1 |  |  |  | (0.5 | ) |  |  | 4.2 |  |  |  | (3.0 | )
Adjusted Net Earnings |  | $ | 70.5 |  |  | $ | 67.0 |  |  | $ | 312.2 |  |  | $ | 225.0 |
Adjusted Net Earnings per share2 |  | $ | 0.14 |  |  | $ | 0.16 |  |  | $ | 0.66 |  |  | $ | 0.57 |

1 | Represents 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 U.S. Tax Reform (see U.S. Tax Reform for additional information).

2 | Per share amount calculated after preferred share dividends and excluding subscription receipts issued for projects or acquisitions not reflected in earnings.

For the three months ended December 31, 2018, Adjusted Net Earnings totaled $70.5 million as compared to Adjusted Net Earnings of $67.0 million for the same period in 2017, an increase of $3.5 million.
For the twelve months ended December 31, 2018, Adjusted Net Earnings totaled $312.2 million as compared to Adjusted Net Earnings of $225.0 million for the same period in 2017, an increase of $87.2 million.

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) |  | 2018 |  |  | 2017 |  |  | 2018 |  |  | 2017 |
Cash flows from operating activities |  | $ | 168.6 |  |  | $ | 116.0 |  |  | $ | 530.4 |  |  | $ | 326.6 |
Add (deduct): |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |
Changes in non-cash operating items |  |  | (27.3 | ) |  |  | 9.1 |  |  |  | 8.1 |  |  |  | 87.7 |
Production based cash contributions from non-controlling interests |  |  | — |  |  |  | — |  |  |  | 13.9 |  |  |  | 7.9 |
Interest expense on convertible debentures and costs related to acquisition financing1 |  |  | — |  |  |  | — |  |  |  | — |  |  |  | 7.2 |
Acquisition-related costs |  |  | (8.8 | ) |  |  | 0.9 |  |  |  | 0.7 |  |  |  | 47.7 |
Reimbursement of operating expenses incurred on joint venture |  |  | — |  |  |  | — |  |  |  | 1.0 |  |  |  | — |
Adjusted Funds from Operations |  | $ | 132.5 |  |  | $ | 126.0 |  |  | $ | 554.1 |  |  | $ | 477.1 |

1 | Exclusive of deferred financing fees of $6.2 million.

For the three months ended December 31, 2018, Adjusted Funds from Operations totaled $132.5 million as compared to Adjusted Funds from Operations of $126.0 million for the same period in 2017, an increase of $6.5 million.
For the twelve months ended December 31, 2018, Adjusted Funds from Operations totaled $554.1 million as compared to Adjusted Funds from Operations of $477.1 million for the same period in 2017, an increase of $77.0 million.

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

CORPORATE DEVELOPMENT ACTIVITIES
The Company’s worldwide development activities for projects either owned directly by the Company or indirectly through AAGES entities are undertaken primarily by AAGES, a joint venture formed with Abengoa. AAGES and its affiliates work with a global reach to identify, develop, and construct new renewable power generating facilities, power transmission lines and water infrastructure assets. Once a project developed by AAGES has reached commercial operation, a determination will be made on whether it will be optimal for such project to be held by APUC, remain in AAGES, or be offered for sale to Atlantica or, in limited circumstances, another party.
The Company has an identified development pipeline of approximately $4.0 billion over the next 5 years consisting of potential investments in $1.4 billion in North American regulated renewable generation assets, $1.7 billion of North American unregulated renewable generation assets, $0.4 billion in regulated electric and gas transmission assets and $0.5 billion in international development projects.
The projects identified are at various stages of development, and have advanced to a stage where the resolutions to major project uncertainties such as regulatory approvals, land control, economic and other contractual issues are probable, but not certain, and it is expected that the project will meet management’s risk adjusted return expectations.
Projects Completed
Great Bay Solar Project
The Great Bay Solar Project is a 75 MW solar powered electric generating facility comprising four sites located in Somerset County in southern Maryland.
The facility is composed of 300,000 solar panels and is located on 400 acres of land. The project is expected to generate 146.0 GW-hrs of energy per year, with all energy sold to the U.S. Government Services pursuant to a 10 year PPA, with a 10 year extension option. All Solar Renewable Energy Credits from the project will be retained by the project company and sold into the Maryland market.
The project achieved commercial operation in two phases: 20 MW on December 30, 2017 and 55 MW on March 29, 2018.
Amherst Island Wind Project
The Amherst Island Wind Project is a 75 MW wind powered electric generating facility located on Amherst Island near the village of Stella, approximately 15 kilometers southwest of Kingston, Ontario.
The project is composed of 26 Siemens 3.2 MW turbines and is expected to produce approximately 235.0 GW-hrs of electrical energy annually, with all energy being sold under a PPA awarded as part of the Independent Electricity System Operator (“IESO”), formerly the Ontario Power Authority.
During the year, the Amherst Project achieved COD, and received notice from the IESO confirming that the FIT term commenced June 15, 2018, and that the FIT contract remains in full force and effect.
During 2018, the Liberty Power Group's interest in the project was held in a joint venture with the EPC contractor; subsequent to year-end, the Liberty Power Group exercised its option to acquire, at a pre-agreed price, the balance of the joint venture interest not previously owned. The acquisition is subject to regulatory approval, which is expected to be obtained in 2019.
Projects in Construction
Turquoise Solar Project
The Turquoise Solar Project is a 10 MW solar powered electric generating development project located in Washoe County in Nevada.
The project is expected to generate 28 GW-hrs of energy per year which will be consumed by the Calpeco Electric System customers.
The Liberty Utilities Group believes that the project will qualify for U.S. federal investment tax credits. Investment in the project by the Calpeco Electric System, net of the third party tax equity investment sought to efficiently use the tax attributes from the project, has been approved by the California Public Utility Commission for inclusion in the rate base of the utility. The cost of energy from the project is forecast to result in savings to the energy costs incurred by the Calpeco Electric System customers.
The project reached mechanical completion in the fourth quarter of 2018, and commissioning is due to be completed in the first quarter of 2019.

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

North American Development Activities
Mid-West Wind Development Project
In 2017, the Liberty Utilities Group presented a plan to the MPSC for an investment in up to 600 MW of strategically located wind energy generation which is forecast to reduce energy costs for its customers. On July 11, 2018, an order was received from the MPSC supporting various requests related to the proposed investment plan.
Effective October 11, 2018, Empire entered into purchase agreements with a developer for two wind development projects, North Fork Ridge and Kings Point, and effective November 16, 2018, entered into a third purchase agreement with another developer for Neosho Ridge, with total combined capacity of 600 MW. The agreements contain development milestones and termination provisions that primarily apply prior to the commencement of construction. Agreements have also been executed for the design and construction of the projects. These projects are located in Kansas and Missouri, within the Empire District Electric System service territory, and are expected to begin construction in the second half of 2019, subject to the receipt of certain regulatory approvals. The estimated construction cycle for the projects is 12 to 18 months.
The proposed new wind generating capacity is forecast to generate approximately 2,400 GW-hrs of energy per year for consumption by the Empire Electric System customers.
The development and construction costs of the three projects comprising the 600 MW plan, net of third party tax equity investment sought to efficiently use the tax attributes from the projects, are expected to be included in the rate base of the Empire Electric System. The cost of energy from the projects is forecast to result in savings to the energy costs incurred by the Empire Electric System customers.
Granite Bridge Project
The Liberty Utilities Group is developing the Granite Bridge Project, which has been conceived to help relieve supply constraints impacting the Liberty Utilities Group’s natural gas distribution customers in order to reduce customer gas energy costs and support continued economic growth. The project comprises a proposed 26 mile natural gas pipeline, connecting the Portland Natural Gas Transmission System, the Maritimes & Northeast Pipeline (Joint Facilities) and the Tennessee Gas Concord Lateral, which provides service to the Liberty Utilities Groups’ New Hampshire distribution system. The pipeline will be constructed in a designated energy infrastructure corridor along Route 101, and will be completely within the New Hampshire Department of Transportation (“NHDOT”) right of way in New Hampshire. In addition, the project includes a proposed 2 bcf full containment storage tank and liquefaction and vaporization equipment, all of which will be located in an abandoned quarry to minimize visual impact to the host community of Epping, New Hampshire.
The Liberty Utilities Group filed for approval of its plan to construct the project with the NHPUC in December 2017, and a decision is expected in 2019.
The Liberty Utilities Group has commenced environmental, geotechnical and survey work on the project, and has received preliminary acceptance from the NHDOT on its proposed pipeline route. The Manchester, Hudson, Nashua, and Concord Chambers of Commerce have publicly endorsed the project, together with the New Hampshire Building Trades. In addition, a bipartisan group of 22 State senators has publicly endorsed the project.
The development and construction costs of the project are expected to be included in the rate base of the EnergyNorth Natural Gas System.
Final investment decision will be made following receipt of NHPUC and New Hampshire Site Evaluation Committee approvals.
Sugar Creek Wind Project
The Sugar Creek Wind Project is a 202 MW wind power electric development project located in Logan County, Illinois. Development of the project is underway. A long-term contract is in place with the Illinois Power Agency to provide renewable energy certificates from the project to utilities in the state. Energy from the project will be sold pursuant to a long-term financial hedge, which was executed in the fourth quarter of 2018 with a creditworthy counterparty. An initial agreement has been entered into to secure construction services for the project, with a definitive agreement expected during the first quarter of 2019. Initial payment has been made for project turbines for an anticipated delivery to site in the second quarter of 2020, and a turbine supply agreement for the project is expected to be signed in the first quarter of 2019. COD for the project is expected in the fourth quarter of 2020.
Blue Hill Wind Project
The Blue Hill Wind Project is a 177 MW wind powered electric generating development project located in the rural municipalities of Lawtonia and Morse in southwest Saskatchewan. The project is expected to generate approximately 800.0 GW-hrs of energy per year, with all energy sold to SaskPower pursuant to a 25 year PPA.
Ministerial approval to proceed with the development of the project was received from the Saskatchewan Ministry of Environment. The project has also received development permits from the municipalities of Lawtonia and Morse.

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

Based on the recently completed system impact study for the project, the expected time frame for design and construction is estimated to be between 24 and 36 months. SaskPower has commenced the Facilities Study phase of the interconnection procedures required to connect the Blue Hill Wind Project to SaskPower’s transmission system. A geotechnical evaluation of the project site including existing infrastructure and municipal roads has been completed. The current project execution plan estimates the COD date for the project to be late 2021 or early 2022.
Val-Éo Wind Project
The Val-Éo Wind Project is a 125 MW wind powered electric generating development project located in the local municipality of Saint-Gideon de Grandmont, near Quebec City. The Liberty Power Group holds a 50% interest in the project through a partnership created with the Val-Éo Wind Cooperative (a community based landowner consortium).
The project will be developed in two phases. Phase I of the project is expected to be completed in 2019 and is expected to have a total capacity of 24 MW, with all energy from Phase I of the project to be sold to Hydro-Québec Distribution pursuant to a 20-year PPA. Phase II of the project would entail the development of an additional 101 MW and would be constructed following the successful evaluation of the wind resource at the site, completion of satisfactory permitting and entering into appropriate energy sales arrangements. All land agreements, construction permits and authorizations have been obtained for Phase I, except for final approval from Transport Canada and an agricultural land use permit expected in the first quarter of 2019.
During the second quarter of 2018, the Liberty Power Group executed an interconnection agreement with Hydro-Québec TransÉnergie. Additionally, the Liberty Power Group executed a revised turbine supply agreement which resulted in approximately C$10 million in cost savings over the initial Phase I project cost estimates. On September 14, 2018, a service and maintenance agreement was executed with the turbine equipment supplier.
Walker Ridge Wind Project
The Walker Ridge Wind Project is a 144 MW wind power electric generating facility located in the counties of Lake and Colusa in northern California. The facility will be located on U.S. Bureau of Land Management land. A Large Generator Interconnection Agreement with CAISO and PG&E was executed in December 2018. Work is ongoing with respect to site design, environmental permitting and EPC engagement. Energy from the project is expected to be sold pursuant to a long term financial hedge. The expected COD date for the project is late 2020 or 2021.
Broad Mountain Wind Project
The Broad Mountain Wind Project is a 200 MW wind power electric generating facility located in Carbon County, Pennsylvania. Development of the project is planned to be completed in two phases. The first phase (“Phase I”) representing installed capacity of 80 MW is targeted for completion, pending regulatory approvals, in 2020. The balance of the 120 MW of proposed capacity is targeted for completion in 2022. The project has secured the majority of land leases required, and environmental and interconnection studies are underway including geotechnical investigations, FAA permits and zoning applications for Phase I. Energy from Phase I of the project is expected to be sold pursuant to a long term financial hedge, and/or PPAs to local end users.
Shady Oaks II Wind Project
The Shady Oaks II Wind Project is a 120 MW expansion of the Liberty Power Group’s operational Shady Oaks Wind Facility, located in Lee County, Illinois. The project will be located on land adjacent to the existing facility, and, subject to interconnection studies that are currently in progress, will connect to the same point of interconnection. Work on environmental permitting and site design are ongoing. Energy from the expansion project is expected to be sold pursuant to a long term financial hedge. The expected COD date for the project is late 2020 or 2021.
Sandy Ridge II Wind Project
The Sandy Ridge II Wind Project is a 60 to 100 MW expansion of the Liberty Power Group’s operational Sandy Ridge Wind Facility, located in Centre County, Pennsylvania. The project will be located on land adjacent to the existing facility, and, subject to interconnection studies that are currently in progress, will connect to the same point of interconnection. Work on environmental permitting and site design is ongoing. Energy from the expansion project is expected to be sold pursuant to a long term financial hedge. The expected COD date for the project is late 2020 or early 2021.
Great Bay II Solar Project
The Great Bay II Solar Project is an approximately 45 MW expansion of the Liberty Power Group’s operational Great Bay Solar Facility, located in Somerset County in southern Maryland. The project will be located on land nearby the existing facility, and will connect to the same point of interconnection. Work on environmental permitting and site design is ongoing. Energy from the expansion project is expected to be sold pursuant to a long-term financial hedge. The expected COD date for the project is late 2019 or early 2020.

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Wataynikaneyap Power Transmission Project
The Liberty Utilities Group acquired a 9.8% ownership interest in an electricity transmission project located in Northwestern Ontario (the “Wataynikaneyap Power Transmission Project”) from Fortis Inc. 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. Ownership of the Wataynikaneyap Power Transmission Project is divided as follows: 9.8% held by the Liberty Utilities Group, 39.2% held by Fortis Inc. and 51% held equally among 24 First Nation partners.
The initial phase of the Wataynikaneyap Power Transmission Project connecting Pikangikum First Nation to Ontario’s power grid was completed in late 2018. The next two phases are subject to receipt of all necessary regulatory approvals, including leave-to-construct approval from the Ontario Energy Board, which is expected in the first half of 2019. 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 the area.
International Development Activities
As a component of the acquisition of its interest in Atlantica, Algonquin secured an opportunity for AAGES to evaluate participation in a number of development opportunities which had been previously advanced by Abengoa. Since its formation in the first quarter of 2018, the AAGES development team has been actively evaluating its interest in international projects, including the following project:
ATN3 Electric Transmission Project
The ATN3 electric transmission project is an electric transmission development project located in southeast Peru consisting of a new 220 kV power transmission line approximately 320 km in length, a new 138 kV power transmission line approximately 7.2 km in length, two new substations and the expansion of three existing substations. The ATN3 Project will be operated under a concession agreement with the government of Peru, with an operating period of 30 years from the commencement of commercial operation and which grants to ATN3 an annual fixed tariff denominated in U.S. dollars and indexed to the U.S. consumer price index. Ownership of the project will be transferred to the government of Peru at the end of the 30 year concession term.
On November 8, 2018, AAGES entered into a definitive agreement with Abengoa Perú S.A. and Abengoa Greenfield Perú S.A. to acquire the entity that owns the project. Closing of the transaction remains subject to certain conditions, including receipt of certain approvals from the government of Peru.

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SUMMARY OF PROPERTY, PLANT, AND EQUIPMENT EXPENDITURES 1

|  | Three Months Ended December 31 |  |  | Twelve Months Ended December 31 |
(all dollar amounts in $ millions) |  | 2018 |  |  | 2017 |  |  | 2018 |  |  | 2017 |
Liberty Utilities Group: |  |  |  |  |  |  |  |  |  |  |  |
Rate Base Maintenance |  | $ | 41.5 |  |  | $ | 45.9 |  |  | $ | 177.7 |  |  | $ | 170.9 |
Rate Base Acquisition |  |  | — |  |  |  | — |  |  |  | — |  |  |  | 2,058.2 |
Rate Base Growth |  |  | 76.0 |  |  |  | 70.6 |  |  |  | 173.9 |  |  |  | 272.7 |
|  | $ | 117.5 |  |  | $ | 116.5 |  |  | $ | 351.6 |  |  | $ | 2,501.8 |
Liberty Power Group: |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |
Maintenance |  | $ | 12.6 |  |  | $ | 3.1 |  |  | $ | 27.4 |  |  | $ | 13.9 |
Investment in Capital Projects1 |  |  | (18.0 | ) |  |  | 13.4 |  |  |  | 71.6 |  |  |  | 469.9 |
International Investments2 |  |  | 345.0 |  |  |  | — |  |  |  | 957.6 |  |  |  | — |
|  | $ | 339.6 |  |  | $ | 16.5 |  |  | $ | 1,056.6 |  |  | $ | 483.8 |
Total Capital Expenditures |  | $ | 457.1 |  |  | $ | 133.0 |  |  | $ | 1,408.2 |  |  | $ | 2,985.6 |

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

2 | Investments in Atlantica are reflected at historical investment cost and not fair value.

2018 Fourth Quarter Property Plant and Equipment Expenditures
During the three months ended December 31, 2018, the Liberty Utilities Group invested $117.5 million in capital expenditures as compared to $116.5 million during the same period in 2017. The Liberty Utilities Group’s investment was primarily related to the construction of transmission and distribution main replacements, work on new and existing substation assets, and initiatives relating to the safety and reliability at the electric and gas systems.
During the three months ended December 31, 2018, the Liberty Power Group incurred capital expenditures of $339.6 million as compared to $16.5 million during the same period in 2017. The Liberty Power Group’s investment was primarily related to the acquisition of an additional 16.5% interest in Atlantica, development costs for the Sugar Creek Wind Project, and ongoing maintenance capital at existing operating sites, partially offset by a repayment of a loan provided to the Amherst Island Wind Project.
2018 Annual Property Plant and Equipment Expenditures
During the twelve months ended December 31, 2018, the Liberty Utilities Group invested $351.6 million in capital expenditures as compared to $2.5 billion during the same period in 2017. Excluding the acquisition of Empire, the Liberty Utilities Group incurred capital expenditures of $443.6 million in 2017. The Liberty Utilities 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, and initiatives relating to the safety and reliability at the electric and gas systems. Capital expenditures in the same period last year (excluding the acquisition of Empire) included the completion of the Luning Solar Facility and further development of Phase I of the North Lake Tahoe transmission project to upgrade the 650 Line (10 miles) which runs from Northstar to Kings Beach, California to 120kV.
During the twelve months ended December 31, 2018, the Liberty Power Group incurred capital expenditures of $1,056.6 million as compared to $483.8 million during the same period in 2017. Excluding the 41.5% investment in Atlantica, the Liberty Power Group’s investment was $99.0 million in 2018. The Liberty Power Group’s investments primarily related to completion of the Great Bay Solar and Amherst Island Wind Facilities, early stages of environmental permitting for the Blue Hill Wind Project, the finalization of material construction contracts on the Val Eo Wind Project and ongoing maintenance capital at existing operating sites.

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

2019 Capital Investments
In 2019, the Company plans to spend between $1.4 billion and $1.6 billion on capital investment opportunities. Actual expenditures during the course of 2019 may vary due to timing of various project investments and the realized Canadian to U.S. dollar exchange rate.
Expected 2019 capital investment ranges are as follows:

(all dollar amounts in $ millions) |  |  |  |  |  |  |  |  |
Liberty Utilities Group: |  |  |  |  |  |  |  |  |
Rate Base Maintenance |  | $ | 180.0 |  |  |  | - |  |  | $ | 200.0 |
Rate Base Growth |  |  | 280.0 |  |  |  | - |  |  |  | 320.0 |
Utility Acquisitions |  |  | 350.0 |  |  |  | - |  |  |  | 370.0 |
Total Liberty Utilities Group: |  | $ | 810.0 |  |  |  | - |  |  | $ | 890.0 |
Liberty Power Group: |  |  |  |  |  |  |  |  |  |  |  |
Maintenance |  | $ | 30.0 |  |  |  | - |  |  | $ | 40.0 |
Investment in Capital Projects |  |  | 340.0 |  |  |  | - |  |  |  | 370.0 |
International Investments |  |  | 220.0 |  |  |  | - |  |  |  | 300.0 |
Total Liberty Power Group: |  | $ | 590.0 |  |  |  | - |  |  | $ | 710.0 |
Total 2019 Capital Investments |  | $ | 1,400.0 |  |  |  | - |  |  | $ | 1,600.0 |

The Liberty Utilities Group intends to spend between $810.0 million - $890.0 million over the course of 2019 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. Projects entail spending capital for structural improvements, specifically in relation to refurbishing substations, replacing poles and wires, drilling and equipping aquifers, main replacements, and reservoir pumping stations. Liberty expects to close the acquisitions of New Brunswick Gas, St. Lawrence Gas and the Turquoise Solar Project in 2019.
The Company expects to fund its 2019 capital plan through a combination of retained cash, tax equity funding, senior and subordinated debentures, bank revolving and term credit facilities, and common equity.
The Liberty Power Group intends to spend between $590.0 million - $710.0 million over the course of 2019 to develop or further invest in capital projects, primarily in relation to: (i) the purchase of the Amherst Island Wind Project from our Joint Venture Partner, (ii) development of the Sugar Creek Wind and Great Bay II Solar Projects, and (iii) additional international investments. The Liberty Power Group plans to spend $30.0 million - $40.0 million on various operational solar, thermal, and wind assets to maintain safety, regulatory, and operational efficiencies.

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LIQUIDITY AND CAPITAL RESERVES
APUC has revolving credit and letter of credit facilities available for Corporate, the Liberty Utilities Group, and the Liberty Power 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, 2018:

|  | As at December 31, 2018 |  |  | As at Dec 31, 2017 |
(all dollar amounts in $ millions) |  | Corporate |  |  | Liberty Utilities |  |  | Liberty Power |  |  | Total |  |  | Total |
Committed facilities |  | $ | 121.0 |  |  | $ | 500.0 |  |  | $ | 700.0 | 1 |  | $ | 1,321.0 |  |  | $ | 1,101.4 |
Funds drawn on facilities/ Commercial paper issued |  |  | — |  |  |  | (103.0 | ) |  |  | — |  |  |  | (103.0 | ) |  |  | (54.3 | )
Letters of credit issued |  |  | (13.5 | ) |  |  | (7.8 | ) |  |  | (149.8 | ) |  |  | (171.1 | ) |  |  | (139.3 | )
Liquidity available under the facilities |  |  | 107.5 |  |  |  | 389.2 |  |  |  | 550.2 |  |  |  | 1,046.9 |  |  |  | 907.8 |
Cash on hand |  |  |  |  |  |  |  |  |  |  |  |  |  |  | 46.8 |  |  |  | 43.5 |
Total Liquidity and Capital Reserves |  | $ | 107.5 |  |  | $ | 389.2 |  |  | $ | 550.2 |  |  | $ | 1,093.7 |  |  | $ | 951.3 |

1 | Includes a $200 million uncommitted stand alone letter of credit facility.

As at December 31, 2018, the Company’s C$165.0 million senior unsecured revolving credit facility (the “Corporate Credit Facility”) was undrawn and had $13.5 million of outstanding letters of credit. In November 2018, the facility’s maturity was extended to November 19, 2019.
On December 21, 2017, the Company entered into a $600.0 million term credit facility with two Canadian banks (“Corporate Term Credit Facility”). The proceeds of the Corporate Term Credit Facility provide the Company with additional liquidity for general corporate purposes and acquisitions. On March 7, 2018 the Company drew $600.0 million under this facility and during the second and fourth quarter the Company repaid $132.5 million and $280.7 million respectively on the facility. In December 2018, the facility's maturity was extended to June 21, 2019. The Company plans to refinance the Corporate Credit Facility and the Corporate Term Credit Facility with a new revolving credit facility in the first half of 2019.
On February 23, 2018, the Liberty Utilities Group increased commitments on its senior unsecured syndicated revolving credit facility (the “Liberty Credit Facility”) to $500.0 million and extended the maturity to February 23, 2023. In conjunction with the increase to the Liberty Credit Facility, the $200.0 million revolving credit facility at Empire was canceled. The Liberty Credit Facility will now be used as a backstop for Empire’s commercial paper program and as a source of liquidity for Empire. As at December 31, 2018 the Liberty Credit Facility had drawn $97.0 million, backstopped $6.0 million in commercial paper issuances, and had $7.8 million in outstanding letters of credit.
As at December 31, 2018, the Liberty Power Group’s bank lines consisted of a $500.0 million senior unsecured syndicated revolving credit facility (the “Liberty Power Credit Facility”) maturing on October 6, 2023 and a $200.0 million letter of credit facility (“Liberty Power LC Facility”) maturing January 31, 2021. As at December 31, 2018, the Liberty Power Credit Facility was undrawn and a total of $149.8 million of letters of credit were issued under this facility and the standalone Liberty Power LC Facility.
Long Term Debt
On June 1, 2018, the Company repaid, upon its maturity, a $90.0 million secured utility note.
On July 25, 2018, the Company repaid, upon its maturity, a C$135.0 million unsecured note.
Issuance of Subordinated Notes
On October 17, 2018, APUC issued $287.5 million of 6.875% fixed-to-floating subordinated notes. The issuance of the subordinated notes represented APUC’s inaugural entry into the U.S. public debt markets. The subordinated notes are listed on the NYSE under the ticker symbol “AQNA”.
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 6.875%. Subsequently, the interest rate will be set to equal the three-month London Interbank Offered Rate (LIBOR) plus a margin of 367.7 basis points from years 5 to 10, a margin of 392.7 basis points from years 10 to 25 and a margin of 467.7 basis points from years 25 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.

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

APUC believes the use of subordinated notes structured as hybrid capital is a cost effective financing method that can be used to obtain balance sheet equity credit. APUC plans to continue to expand this portion of its capital structure as a means to diversify its financing sources.
Issuance of Green Bonds
Subsequent to year-end on January 29, 2019, the Liberty Power 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 Liberty Power Group’s inaugural “green bond” offering, and are closely aligned with the Company’s commitment to advancing a sustainable energy and water future. Under its recently implemented Green Bond Framework, the proceeds of any “green bond” offering are to be used to finance and/or refinance investments in renewable power generation and clean energy technologies.
As at December 31, 2018, the weighted average tenor of APUC’s total long term debt is approximately 17 years with an average interest rate of 4.8%.
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.
LUCo, parent company for the Liberty Utilities 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”).
APCo, the parent company for the Liberty Power Group, has a BBB issuer rating from S&P, a BBB issuer rating from DBRS and a BBB issuer rating from Fitch.
Contractual Obligations
Information concerning contractual obligations as of December 31, 2018 is shown below:

(all dollar amounts in $ millions) |  | Total |  |  | Due less than 1 year |  |  | Due 1 to 3 years |  |  | Due 4 to 5 years |  |  | Due after 5 years |
Principal repayments on debt obligations1 |  | $ | 3,321.8 |  |  | $ | 334.9 |  |  | $ | 420.8 |  |  | $ | 825.6 |  |  | $ | 1,740.5 |
Convertible debentures |  |  | 0.5 |  |  |  | — |  |  |  | — |  |  |  | — |  |  |  | 0.5 |
Advances in aid of construction |  |  | 63.7 |  |  |  | 1.2 |  |  |  | — |  |  |  | — |  |  |  | 62.5 |
Interest on long-term debt obligations2 |  |  | 1,576.9 |  |  |  | 156.8 |  |  |  | 269.9 |  |  |  | 221.5 |  |  |  | 928.7 |
Purchase obligations |  |  | 325.3 |  |  |  | 325.3 |  |  |  | — |  |  |  | — |  |  |  | — |
Environmental obligations |  |  | 59.2 |  |  |  | 4.2 |  |  |  | 30.1 |  |  |  | 2.9 |  |  |  | 22.0 |
Derivative financial instruments: |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |
Cross currency swap |  |  | 93.2 |  |  |  | 5.3 |  |  |  | 46.0 |  |  |  | 34.4 |  |  |  | 7.5 |
Interest rate swap |  |  | 8.5 |  |  |  | 8.5 |  |  |  | — |  |  |  | — |  |  |  | — |
Energy derivative and commodity contracts |  |  | 1.2 |  |  |  | 0.6 |  |  |  | 0.5 |  |  |  | 0.1 |  |  |  | — |
Purchased power |  |  | 282.6 |  |  |  | 46.5 |  |  |  | 22.0 |  |  |  | 22.9 |  |  |  | 191.2 |
Gas delivery, service and supply agreements |  |  | 251.8 |  |  |  | 77.7 |  |  |  | 79.0 |  |  |  | 46.8 |  |  |  | 48.3 |
Service agreements |  |  | 512.0 |  |  |  | 43.7 |  |  |  | 77.5 |  |  |  | 78.2 |  |  |  | 312.6 |
Capital projects |  |  | 76.8 |  |  |  | 67.6 |  |  |  | 1.9 |  |  |  | 7.3 |  |  |  | — |
Operating leases |  |  | 214.4 |  |  |  | 7.6 |  |  |  | 14.3 |  |  |  | 13.9 |  |  |  | 178.6 |
Other obligations |  |  | 155.8 |  |  |  | 33.4 |  |  |  | — |  |  |  | — |  |  |  | 122.4 |
Total Obligations |  | $ | 6,943.7 |  |  | $ | 1,113.3 |  |  | $ | 962.0 |  |  | $ | 1,253.6 |  |  | $ | 3,614.8 |

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, however management intent is to repay in 2023 upon exercising its redemption right.

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Equity
The common shares of APUC are publicly traded on the Toronto Stock Exchange (“TSX”) and the New York Stock Exchange (“NYSE”) under the trading symbol “AQN”. As at December 31, 2018, APUC had 488,851,433 issued and outstanding common shares.
APUC may issue an unlimited number of common shares. The holders of common shares are entitled to dividends, if and when declared; to one vote for each share at meetings of the holders of common shares; and to receive a pro rata share of any remaining property and assets of APUC upon liquidation, dissolution or winding up of APUC. All shares are of the same class and with equal rights and privileges and are not subject to future calls or assessments.
On April 24, 2018, APUC closed the sale of approximately 37.5 million of its common shares to certain institutional investors at a price of C$11.85 per share, for gross proceeds of approximately C$444.4 million. The proceeds of the offering were used to pay down existing indebtedness and in part, to finance the purchase of the additional 16.5% interest in Atlantica.
On December 20, 2018, APUC closed the sale of approximately 12.5 million of its common shares to certain institutional investors at a price of C$13.76 per share, for gross proceeds of approximately C$172.5 million. The proceeds of the offering are anticipated to be used to partially finance APUC’s recently announced acquisition of New Brunswick Gas, and for general corporate purposes.
APUC is also authorized to issue an unlimited number of preferred shares, issuable in one or more series, containing terms and conditions as approved by the Board. As at December 31, 2018, 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 5.0% annually for the initial five year period ending on March 31, 2019.

APUC has a shareholder dividend reinvestment plan (the “Reinvestment Plan”) for registered holders of common shares of APUC. As at December 31, 2018, 123,522,018 common shares representing approximately 25% of total common shares outstanding had been registered with the Reinvestment Plan. During the year ended December 31, 2018, 5,880,843 common shares were issued under the Reinvestment Plan, and subsequent to year-end, on January 17, 2019, an additional 1,606,001 common shares were issued under the Reinvestment Plan.
SHARE-BASED COMPENSATION PLANS
For the twelve months ended December 31, 2018, APUC recorded $9.5 million in total share-based compensation expense as compared to $8.4 million for the same period in 2017. There is no tax benefit associated with the share-based compensation expense. The compensation expense is recorded as part of administrative expenses in the consolidated statement of operations. The portion of share-based compensation costs capitalized as cost of construction is insignificant.
As at December 31, 2018, total unrecognized compensation costs related to non-vested options and share unit awards were $1.2 million and $8.2 million, respectively, and are expected to be recognized over a period of 1.64 and 1.60 years, respectively.
Stock Option Plan
APUC has a stock option plan that permits the grant of share options to key officers, directors, employees and selected service providers. Except in certain circumstances, the term of an option shall not exceed ten (10) years from the date of the grant of the option.
APUC determines the fair value of options granted using the Black-Scholes option-pricing model. The estimated fair value of options, including the effect of estimated forfeitures, is recognized as expense on a straight-line basis over the options’ vesting periods while ensuring that the cumulative amount of compensation cost recognized at least equals the value of the vested portion of the award at that date. During the twelve months ended December 31, 2018, the Company granted 1,166,717 options to executives of the Company. The options allow for the purchase of common shares at a weighted average price of C$12.80, the market price of the underlying common share at the date of grant. During the year, executives of the Company exercised 1,493,694 stock options at a weighted average exercise price of C$10.66 in exchange for common shares issued from treasury and 95,517 options were settled at their cash value as payment for tax withholdings related to the exercise of the options.
As at December 31, 2018, a total of 6,292,642 options are issued and outstanding under the stock option plan.

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

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, 2018, the Company granted (including dividends and performance adjustments) 791,524 PSUs and RSUs to executives and employees of the Company. During the year, the Company settled 285,551 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 2018, a total of 68,869 PSUs were forfeited.
As at December 31, 2018, a total of 1,392,132 PSUs and RSUs are granted and outstanding under the PSU and RSU plan.
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, 2018, the Company issued 86,750 DSUs (including DSUs in lieu of dividends) to the directors of the Company.
As at December 31, 2018, a total of 380,656 DSUs had been granted under the DSU plan.
Bonus Deferral Restricted Share Units
During the year, the Company introduced a new bonus deferral restricted share units (“RSUs”) program 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, 2018, 131,611 RSUs were issued (including RSUs in lieu of dividends) to employees of the Company. During the year, the Company settled 4,545 RSUs in exchange for 2,111 common shares issued from treasury, and 2,434 RSUs were settled at their cash value as payment for tax withholdings related to the settlement of the RSUs.
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, 2018, the Company issued 252,698 common shares to employees under the ESPP.
As at December 31, 2018, a total of 1,032,251 shares had been issued under the ESPP.

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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 2018 and 2017 (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 $11.4 million in 2018 as compared to $4.7 million during the same period in 2017 (see Note 8(d) and 8(e) in the annual audited consolidated financial statements).
Subject to certain limitations, Atlantica has a right of first offer on any proposed sale, transfer or other disposition by AAGES (other than to APUC) of its interest in infrastructure facilities that are developed or constructed in whole or in part by AAGES under long-term revenue agreements. Similarly, Atlantica has rights, subject to certain limitations, with respect to any proposed sale, transfer or other disposition of APUC’s interest, not held through AAGES, in infrastructure facilities that are developed or constructed in whole or in part by APUC outside of Canada or the United States under long-term revenue agreements. There were no such transactions in 2018 (see Note 8(a) and 8(b) in the annual audited consolidated financial statements).
Redeemable non-controlling interests
In 2018, contributions of $305.0 million were received from AAGES for preference shares of a wholly consolidated subsidiary of the Company (see Note 8(a) and Note 17 in the annual audited consolidated financial statements).
Long Sault Hydro Facility
Effective December 31, 2013, APUC acquired the shares of Algonquin Power Corporation Inc. (“APC”) which was partially owned by Senior Executives. APC owns the partnership interest in the 18 MW Long Sault Hydro Facility. A final post-closing adjustment related to the transaction remains outstanding.
The above related party transactions have been recorded at the exchange amounts agreed to by the parties to the transactions.

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

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 31000:2009 and the 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’ business risks is set out in the Company’s most recent AIF available on SEDAR.
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. APCo, the primary operating company of the Liberty Power Group, has a BBB issuer rating from S&P, BBB issuer rating from DBRS and a BBB issuer rating from Fitch. LUCo, parent company for the Liberty Utilities 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.
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. 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 impaired or made more difficult or expensive. Therefore, any such downgrades could have a material adverse effect on APUC’s business, cost of capital, financial condition and results of operations.
The Company is not adopting or endorsing such ratings, and such ratings do not indicate APUC’s assessment of its own ability to pay the interest or principal of debt securities it issues. The Company is providing such ratings only to assist with the assessment of future risks and effects of ratings on the Company’s financing costs.
No assurances can be provided that any of APUC’s current ratings will remain in effect for any given period of time or that a rating will not be lowered or withdrawn entirely by a rating agency if, in its judgment, circumstances in the future so warrant.
Capital Markets and Liquidity Risk
As at December 31, 2018, the Company had approximately $3,337.3 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.

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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.
Based on amounts outstanding as at December 31, 2018, the impact to interest expense from changes in interest rates are as follows:

• | The Corporate Credit Facility is subject to a variable interest rate and had no amounts outstanding as at December 31, 2018. As a result, a 100 basis point change in the variable rate charged would not impact interest expense;

• | The Liberty Utilities Group’s revolving credit facility is subject to a variable interest rate and had $97.0 million outstanding as at December 31, 2018. As a result, a 100 basis point change in the variable rate charged would impact interest expense by $1.0 million annually;

• | The Liberty Utilities Group’s commercial paper program is subject to a variable interest rate and had $6.0 million outstanding as at December 31, 2018. As a result, a 100 basis point change in the variable rate charged would impact interest expense by $0.1 million annually;

• | The Liberty Power Group’s revolving credit facility is subject to a variable interest rate and had no amounts outstanding as at December 31, 2018. As a result, a 100 basis point change in the variable rate charged would not impact interest expense; and

• | The corporate term facilities are subject to a variable interest rate and had $321.8 million outstanding as at December 31, 2018. As a result, a 100 basis point change in the variable rate charged would impact interest expense by $3.2 million annually.

To mitigate financing risk, from time to time APUC may seek to fix interest rates on expected future financings. In the fourth quarter of 2014, the Liberty Power Group entered into a 10-year forward starting swap to fix the underlying interest rate for the anticipated refinancing of its C$135.0 million bond which matured in July 2018. On July 24, 2018, the Company amended and extended the forward-starting date of the interest rate swap to begin on March 29, 2019. Subsequent to year-end and concurrent with the issuance of C$300.0 million of senior unsecured debentures on January 29, 2019 this swap was unwound and settled.

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Tax Risk and Uncertainty
The Company is subject to income and other taxes primarily in the United States and Canada. Changes in tax laws or interpretations thereof in the jurisdictions in which APUC does business could adversely affect the Company’s results from operations, our return to shareholders, and cash flow.
The Company cannot provide assurance that the Canada Revenue Agency, the Internal Revenue Service or any other applicable taxation authority will agree with the tax positions taken by the Company, including with respect to claimed expenses and the cost amount of the Company’s depreciable properties. A successful challenge by an applicable taxation authority regarding such tax positions could adversely affect our results of operations and financial position.
Development by the Liberty Power Group of renewable power generation facilities in the United States depends in part on federal tax credits and other tax incentives. Although these incentives have been extended on multiple occasions, the most recent extension provides for a multi-year step-down. While recently enacted U.S. tax reform legislation did not make any changes to the multi-year step-down, there can be no assurance that there will not be further changes in the future. If these incentives are reduced or APUC is unable to complete construction on anticipated schedules, the reduced incentives may be insufficient to support continued development and construction of renewable power facilities in the United States or may result in substantially reduced benefits from facilities that APUC is committed to complete. In addition, the Liberty Power Group has entered into certain tax equity financing transactions with financial partners for certain of its renewable power facilities in the United States, under which allocations of future cash flows to the Company from the applicable facility could be adversely affected in the event that there are changes in U.S. tax laws that apply to facilities previously placed in service.
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 will affect the Company (See U.S. Tax Reform). The U.S. Department of Treasury has released proposed regulations related to business interest expense limitations, Base Erosion Anti-Abuse Tax (“BEAT”), and anti-hybrid structures as part of the implementation of U.S. Tax Reform. These proposed regulations are not final and are subject to change in the regulatory review process which is expected to be completed later in 2019. 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 beyond those described herein.
Credit/Counterparty Risk
APUC and its subsidiaries, through its long term power purchase contracts, trade receivables, derivative financial instruments and short term investments, are subject to credit risk with respect to the ability of customers and other counterparties to perform their obligations to the Company.
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 |  |  | $ | 25.5 |  |  |  | 1.5 | %
Manitoba Hydro |  |  | A+ |  |  |  | 21.0 |  |  |  | 1.3 | %
Hydro Quebec |  | AA- |  |  |  | 21.4 |  |  |  | 1.3 | %
Commonwealth Edison |  | BBB |  |  |  | 19.4 |  |  |  | 1.2 | %
Xcel Energy |  |  | A3 |  |  |  | 17.2 |  |  |  | 1.0 | %
Pacific Gas and Electric Company |  |  | D |  |  |  | 22.0 |  |  |  | 1.3 | %
Wolverine Power Supply |  |  | A |  |  |  | 24.2 |  |  |  | 1.5 | %
Independent Electricity System Operator of Ontario |  |  | A+ |  |  |  | 16.3 |  |  |  | 1.0 | %
Electric Reliability Council of Texas (ERCOT) |  | Aa3 |  |  |  | 11.9 |  |  |  | 0.7 | %
Connecticut Light and Power |  |  | A3 |  |  |  | 23.1 |  |  |  | 1.4 | %
Total |  |  |  |  |  | $ | 202.0 |  |  |  |  |

1 | Ratings by DBRS, Moody’s, or S&P.

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

Liberty Power Group’s revenues are approximately 14% of total Company revenues. Approximately 84% of the Liberty Power Group’s revenues are earned from large utility customers having a credit rating of Baa2 or better by Moody’s, or BBB or higher by S&P, or BBB or higher by DBRS.
The remaining revenue of the Company is primarily earned by the Liberty Utilities Group. In this regard, the credit risk attributed to the Liberty Utilities Group’s accounts receivable balances at the water and wastewater distribution systems total $21.5 million which is spread over approximately 164,000 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 $35.1 million, while electric distribution systems accounts receivable balances related to the electric utilities total $150.2 million. The natural gas and electrical utilities both derive over 85% of their revenue from residential customers and have a per connection average outstanding balance of $104 dollars and $565 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 power purchase agreement with the Liberty Power Group is unable to perform, the Liberty Power Group may be unable to replace the contract on comparable terms, in which case sales of power (and, if applicable, renewable energy credits and ancillary services) from the facility would be subject to market price risk and may require refinancing of indebtedness related to the facility or otherwise have a material adverse effect. Default by other counterparties, including counterparties to hedging contracts that are in an asset position and to short-term investments, also could adversely affect the financial results of the Corporation.
Market Price Risk
The Liberty Power Group predominantly enters into long term PPAs for its generation assets and hence is not exposed to market risk for this portion of its portfolio. Where a generating asset is not covered by a power purchase contract, the Liberty Power Group may seek to mitigate market risk exposure by entering into financial or physical power hedges requiring that a specified amount of power be delivered at a specified time in return for a fixed price. There is a risk that the Company is not able to generate the specified amount of power at the specified time resulting in production shortfalls under the hedge that then requires the Company to purchase power in the merchant market. To mitigate the risk of production shortfalls under hedges, the Liberty Power Group generally seeks to structure hedges to cover less than 100% of the anticipated production, thereby reducing the risk of not producing the minimum hedge quantities. Nevertheless, due to unpredictability in the natural resource or due to grid curtailments or mechanical failures, production shortfalls may be such that the Liberty Power Group may still be forced to purchase power in the merchant market at prevailing rates to settle against a hedge.
Hedges currently put in place by the Liberty Power Group for its operating facilities along with residual exposures to the market are detailed below:
The July 1, 2012 acquisition of the Sandy Ridge Wind Facility included a financial hedge, which commenced on January 1, 2013, for a 10 year period. The financial hedge is structured to hedge 72% of the Sandy Ridge Wind Facility’s expected production volume against exposure to PJM Western Hub current spot market rates. The annual unhedged production based on long term projected averages is approximately 44,000 MW-hrs annually. Therefore, each $10 per MW-hr change in the market price would result in a change in revenue of approximately $0.4 million for the year.
A second hedge for the Sandy Ridge Wind Facility will commence on January 1, 2023, for a one year period. The financial hedge is structured to hedge 73% of the Sandy Ridge Wind Facility’s expected production volume against exposure to PJM Western Hub current spot market rates. The annual unhedged production based on long term projected averages is approximately 42,000 MW-hrs annually.
A third hedge for the Sandy Ridge Wind Facility will commence on January 1, 2024, for a five year period. The financial hedge commitment is declining over the five year period and is structured to hedge 74% of the Sandy Ridge Wind Facility’s expected production volume against exposure to PJM Western Hub current spot market rates in 2024, stepping down to 19% by 2028. The annual unhedged production based on long term projected averages is approximately 41,000 MW-hrs in 2024, stepping up to 128,000 MW-hrs by 2028.
The December 10, 2012 acquisition of the Senate Wind Facility included a physical hedge, which commenced on January 1, 2013, for a 15 year period. The physical hedge is structured to hedge 64% of the Senate Wind Facility’s expected production volume against exposure to ERCOT North Zone current spot market rates. The annual unhedged production based on long term projected averages is approximately 188,000 MW-hrs annually. Therefore, each $10 per MW-hr change in the market price would result in a change in revenue of approximately $2.0 million for the year.
The December 10, 2012 acquisition of the Minonk Wind Facility included a financial hedge, which commenced on January 1, 2013, for a 10 year period. The financial hedge is structured to hedge 73% of the Minonk Wind Facility’s expected production volume against exposure to PJM Northern Illinois Hub current spot market rates. The annual unhedged production based on long term projected averages is approximately 186,000 MW-hrs annually. Therefore, each $10 per MW-hr change in market prices would result in a change in revenue of approximately $2.0 million for the year.

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A second hedge for the Minonk Wind Facility will commence on January 1, 2023, for a one year period. The financial hedge is structured to hedge 72% of the Minonk Wind Facility’s expected production volume against exposure to PJM Northern Illinois Hub current spot market rates. The annual unhedged production based on long term projected averages is approximately 189,000 MW-hrs annually.
A third hedge for the Minonk Wind Facility will commence on January 1, 2024, for a one year period. The financial hedge is structured to hedge 37% of the Minonk Wind Facility’s expected production volume against exposure to PJM Northern Illinois Hub current spot market rates. The annual unhedged production based on long term projected averages is approximately 423,000 MW-hrs annually.
Under each of the above noted hedges, if production is not sufficient to meet the unit quantities under the hedge, the shortfall must be purchased in the open market at market rates. The effect of this risk exposure could be material but cannot be quantified as it is dependent on both the amount of shortfall and the market price of electricity at the time of the shortfall.
In addition to the above noted hedges, from time to time the Liberty Power Group enters into short-term derivative contracts (with terms of one to three months) to further mitigate market price risk exposure due to production variability. As at December 31, 2018, the Liberty Power Group had entered into hedges with a cumulative notional quantity of 7,440 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 $41.6 million.
Commodity Price Risk
The Liberty Power Group’s exposure to commodity prices is primarily limited to exposure to natural gas price risk. The Liberty Utilities Group is exposed to energy and natural gas price risks at its electric and natural gas systems. In this regard, a discussion of this risk is set out as follows:

| • | The Sanger Thermal Facility’s PPA includes provisions which reduce its exposure to natural gas price risk. In this regard, a $1.00 increase in the price of natural gas per MMBTU, based on expected production levels, would result in a decrease in net revenue by approximately $0.1 million on an annual basis.

| • | The Windsor Locks Thermal Facility’s Energy Services Agreement includes provisions which reduce its exposure to natural gas price risk but has exposure to market rate conditions for sales above those to its primary customer. In this regard, a $1.00 increase in the price of natural gas per MMBTU, based on expected production levels, would result in a decrease in net revenue by approximately $0.5 million on an annual basis.

| • | The Maritime region provides short-term energy requirements to various customers at fixed rates. The energy requirements of these customers are estimated at approximately 190,000 MW-hrs in fiscal 2019, 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 short-term financial energy hedge contracts which cover approximately 27% of the Maritime region’s anticipated purchases during the price-volatile winter months at an average rate of approximately $77 per MW-hr. For the amount of anticipated purchases not covered by hedge contracts, each $10.00 change per MW-hr in the market prices in ISO-NE would result in a change in expense of $0.3 million on an annualized basis.

The Calpeco Electric System provides electric service to the Lake Tahoe California basin and surrounding areas at rates approved by the 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.

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The Granite State Electric System is an open access electric utility allowing for its customers to procure commodity services from competitive energy suppliers. For those customers that do not choose their own competitive energy supplier, Granite State Electric System provides a Default Service offering to each class of customers through a competitive bidding process. This process is undertaken semi-annually for all customers. The winning bidder is obligated to provide a full requirements service based on the actual needs of the Granite State Electric System’s Default Service customers. Since this is a full requirements service, the winning bidder(s) take on the risk associated with fluctuating customer usage and commodity prices. The supplier is paid for the commodity by the Granite State Electric System which in turns receives pass-through rate recovery through a formal filing and approval process with the NHPUC on a semi-annual basis. The Granite State Electric System is only committed to the winning Default Service supplier(s) after approval by the NHPUC so that there is no risk of commodity commitment without pass-through rate recovery.
The EnergyNorth Natural Gas System purchases pipeline capacity, storage and commodity from a variety of counterparties. The EnergyNorth Natural Gas System’s portfolio of assets and its planning and forecasting methodology are approved by the NHPUC bi-annually through Least Cost Integrated Resource Plan filing. In addition, EnergyNorth Natural Gas System files with the NHPUC for recovery of its transportation and commodity costs on a semi-annual basis through the Cost of Gas (“COG”) filing and approval process. The EnergyNorth Natural Gas System establishes rates for its customers based on the NHPUC approval of its filed COG. These rates are designed to fully recover its anticipated transportation and commodity costs. In order to minimize commodity price fluctuations, the EnergyNorth Natural Gas System locks in a fixed price basis for approximately 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 rates in said filing. Should commodity prices increase or decrease relative to the initial semi-annual COG rate filing, the EnergyNorth Natural Gas System has the right to automatically adjust its rates going forward in order to minimize any under or over collection of its gas costs. In addition, any under collections may be carried forward with interest to the next year’s corresponding COG filing, i.e. winter to winter and summer to summer.
The Midstates Gas Systems purchases pipeline capacity, storage and commodity from a variety of counterparties, and files with the three individual state commissions for recovery of its transportation and commodity costs through an annual Purchase Gas Adjustment (“PGA”) filing and approval process. The Midstates Gas Systems establishes rates for its customers within the PGA filing and these rates are designed to fully recover its anticipated transportation and commodity costs. In order to minimize commodity price fluctuations, the Company has implemented a commodity hedging program designed to hedge approximately 25-50% of its non-storage related commodity purchases. All gains and losses associated with the hedging 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 gas segment’s 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.
Empire has a fuel cost recovery mechanism in all of its jurisdictions, as such impacts on net income exposure to commodity cost fluctuations are significantly reduced. However, cash flow could still be impacted by any increased expenditures. Empire met approximately 41% of its 2018 generation fuel supply need through coal. Approximately 98% of its 2018 coal supply was Western coal. Empire has contracts and binding proposals to supply a portion of the fuel for its coal plants through 2019. These contracts and inventory on hand satisfy approximately 50% of anticipated fuel requirements for 2019 for the Asbury Coal Facility.
Empire is exposed to changes in market prices for natural gas needed to run combustion turbine generators. Empire’s natural gas procurement program is designed to manage costs to avoid volatile natural gas prices. Empire periodically enters into physical forward and financial derivative contracts with counterparties to meet future natural gas requirements by locking in prices (with respect to predetermined percentages of our expected future natural gas needs) in an attempt to lessen the volatility in fuel expenditures and improve predictability. Gains and losses associated with the hedging program are passed through to customers in the fuel adjustment clause and PGA filings and are embedded in the approved rates in such filings.

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OPERATIONAL RISK MANAGEMENT
Mechanical and Operational Risks
APUC’s profitability could be impacted by, among other things, equipment failure, the failure of a major customer to fulfill its contractual obligations under its PPA, reductions in average energy prices, a strike or lock-out at a facility, natural disasters, interruption in supply chain and expenses related to claims or clean-up to adhere to environmental and safety standards.
The Liberty Utilities Group’s water and wastewater distribution systems operate under pressurized conditions within pressure ranges approved by regulators. Should a water distribution network become compromised or damaged, the resulting release of pressure could result in serious injury or death to individuals or damage to other property.
The Liberty Utilities Group’s electric distribution systems are subject to storm events, usually winter storm events, whereby power lines can be brought down, with the attendant risk to individuals and property. In addition, in forested areas, power lines brought down by wind can ignite forest fires which also bring attendant risk to individuals and property.
The Liberty Utilities Group’s natural gas distribution systems are subject to risks which may lead to fire and/or explosion which may impact life and property. Risks include third party damage, compromised system integrity, type/age of pipelines, and severe weather events.
The Liberty Power Group’s hydro assets utilize dams to pond water for generation and if the dams fail/breach potentially catastrophic amounts of water would flood downriver from the facility. The dams can be subjected to drought conditions and lose the ability to generate during peak load conditions, causing the facilities to fall short of either hedged or PPA committed production levels. The risks of the hydro facilities are mitigated by regular dam inspections and a maintenance program of the facility to lessen the risk of dam failure.
The Liberty Power Group’s wind assets could catch on fire and, depending on the season, could ignite significant amounts of forest or crop downwind from the wind farms. The wind units could also be affected by large atmospheric conditions, which will lower wind levels below our PPA and hedge minimum production levels. The wind units can experience failures in the turbine blades or in the supporting towers. Production risks associated with the wind turbine generators failures is mitigated by properly maintaining the units, using long term maintenance agreements with the turbine O&Ms which provide for regular inspections and maintenance of property, and liability insurance policies. Icing can be mitigated by shutting down the unit as icing is detected at the site.
The Liberty Power Group’s Thermal Energy Division uses natural gas and oil, and produces exhaust gases, which if not properly treated and monitored could cause hazardous chemicals to be released into the atmosphere. The units could also be restricted from purchasing gas/oil due to either shortages or pollution levels, which could hamper output of the facility. The mechanical and operational risks at the thermal facilities are mitigated through the regular maintenance of the boiler system, and by continual monitoring of exhaust gases. Fuel restrictions can be hedged in part by long term purchases.
All of the Liberty Power Group’s electric generating stations are subject to mechanical breakdown. The risk of mechanical breakdown is mitigated by properly maintaining the units and by regular inspections.
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 Liberty Power Group hydroelectric facilities, water rights are generally owned by governments that reserve the right to control water levels, which may affect revenue.
The Liberty Utilities Group’s facilities are subject to rate setting by state regulatory agencies. The Liberty Utilities Group operates in 12 different states and therefore is subject to regulation from 12 different regulatory agencies. The time between the incurrence of costs and the granting of the rates to recover those costs by state regulatory agencies is known as regulatory lag. As a result of regulatory lag, inflationary effects may impact the ability to recover expenses, and profitability could be impacted. In order to mitigate this exposure, the Liberty Utilities Group seeks to obtain approval for regulatory constructs in the states in which it operates to allow for timely recovery of operating expenses. A fundamental risk faced by any regulated utility is the disallowance of costs to be placed into its revenue requirement by the utility’s regulator. To the extent proposed costs are not allowed into rates, the utility will be required to find other efficiencies or cost savings to achieve its allowed returns.
The Liberty Utilities Group regularly works with its governing authorities to manage the affairs of the business, employing both local, state level, and corporate resources.

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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 a significant impact on regulatory revenue requirements of most public utilities, including the Liberty Utilities Group. Throughout the course of 2018, the Liberty Utilities Group obtained orders from the majority of its principal regulators covering approximately 93% of customers, resulting in the reduction of customer rates in connection with the reduction in tax rates. Collectively, the orders represent an annualized aggregate reduction in utility revenues of approximately $35 million, of which approximately $18 million has been realized in 2018. Since the Company has not yet received rate orders addressing 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 Liberty Utilities Group’s distribution systems could be subject to condemnation or other methods of taking by government entities under certain conditions. Any taking by government entities would legally require fair compensation to be paid. Determination of such fair compensation is undertaken pursuant to a legal proceeding and, therefore, there is no assurance that the value received for assets taken will be in excess of book value.
Apple Valley Condemnation Proceedings
On January 7, 2016, the Town of Apple Valley filed a lawsuit seeking to condemn the utility assets of Liberty Utilities (Apple Valley Ranchos Water) Corp (“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 Court has been briefed on a related California Environmental Quality Act (“CEQA”) lawsuit (challenging the Town’s compliance with CEQA in connection with the proposed condemnation) and heard oral argument in December 2017. The Court issued the CEQA decision on February 9, 2018 denying Liberty Apple Valley’s CEQA claim. As a result, the condemnation case will proceed. At present, discovery related to the first phase of the trial is ongoing. The trial date has been set for September 30, 2019 and is expected to last approximately four weeks. 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 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.
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 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.

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Joint Venture Investment Risk
The Company has, and will in the future continue to have, an equity interest of 50% or less in certain projects. As a result, the Company will not control such projects and may be subject to the decision-making of third parties, whose interests may not always be aligned with those of the Company. This may limit the Company’s flexibility and financial returns with respect to these projects.
The Company has, and will in the future continue to have, an interest in projects over which it does not have sole control. Despite having a 50% equity stake in AAGES, the joint venture involves risks, including, among others, a risk that Abengoa:

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

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

• | may 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 AAGES and the Company;

• | may have to give its consent with respect to certain major decisions;

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

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

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

Further, the Company will not have sole control of certain major decisions relating to the projects that the Company owns or pursues through AAGES, including, among others, decisions relating to funding and transactions with affiliates. 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 (see Note 8(a) in the annual audited consolidated financial statements).
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
Liberty Utilities Group
The Liberty Utilities Group’s demand for water is affected by weather conditions and temperature. Demand for water during warmer months is generally greater than cooler months due to requirements for irrigation, swimming pools, cooling systems and other outside water use. If there is above normal rainfall or rainfall is more frequent than normal the demand for water may decrease, adversely affecting revenues.
The Liberty Utilities Group’s demand for energy from its electric distribution systems is primarily affected by weather conditions and conservation initiatives. The Liberty Utilities Group provides information and programs to its customers to encourage the conservation of energy. In turn, demand may be reduced which could have short term adverse impacts on revenues.
The Liberty Utilities Group’s primary demand for natural gas from its natural gas distribution systems is driven by the seasonal heating requirements of its residential, commercial, and industrial customers. The colder the weather the greater the demand for natural gas to heat homes and businesses. As such, the natural gas distribution systems demand profiles typically peaks in the winter months of January and February and declines in the summer months of July and August. Year to year variability also occurs depending on how cold the weather is in any particular year.

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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 Liberty Utilities Group has successfully obtained regulatory approval to implement such decoupling mechanisms in 6 of 12 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.
Liberty Power Group
The Liberty Power Group’s hydroelectric operations are impacted by seasonal fluctuations and year to year variability of the available hydrology. These assets are primarily “run-of-river” and as such fluctuate with natural water flows. During the winter and summer periods, flows are generally lower while during the spring and fall periods flows are generally higher. The ability of these assets to generate income may be impacted by changes in water availability or other material hydrologic events within a watercourse. Year to year the level of hydrology varies, impacting the amount of power that can be generated in a year.
The Liberty Power Group’s wind generation facilities are impacted by seasonal fluctuations and year to year variability of the wind resource. During the fall through spring period, winds are generally stronger than during the summer periods. The ability of these facilities to generate income may be impacted by naturally occurring changes in wind patterns and wind strength.
The Liberty Power Group’s solar generation facilities are impacted by seasonal fluctuations and year to year variability in the solar radiance. For instance, there are more daylight hours in the summer than there are in the winter, resulting in higher production in the summer months. The ability of these facilities to generate income may be impacted by naturally occurring changes in solar radiance.
The Company attempts to mitigate the above noted natural resource fluctuation risks by acquiring or developing generating stations in different geographic locations.
Development and Construction Risk
The Company actively engages in the development and construction of new power generation facilities. There is always a risk that material delays and/or cost overruns could be incurred in any of the projects planned or currently in construction affecting the Company’s overall performance. There are risks that actual costs may exceed budget estimates, delays may occur in obtaining permits and materials, suppliers and contractors may not perform as required under their contracts, there may be inadequate availability, productivity or increased cost of qualified craft labor, start-up activities may take longer than planned, the scope and timing of projects may change, and other events beyond the Company’s control may occur that may materially affect the schedule, budget, cost and performance of projects. Regulatory approvals can be challenged by a number of mechanisms which vary across state and provincial jurisdictions. Such permitting challenges could identify issues that may result in permits being modified or revoked.
Risks Specific to Renewable Generation Projects:
The strength and consistency of the wind resource will vary from the estimate set out in the initial wind studies that were relied upon to determine the feasibility of the wind facility. If weather patterns change or the historical data proves not to accurately reflect the strength and consistency of the actual wind, the assumptions underlying the financial projections as to the amount of electricity to be generated by the facility may be different and cash could be impacted.
The amount of solar radiance will vary from the estimate set out in the initial solar studies that were relied upon to determine the feasibility of the solar facility. If weather patterns change or the historical data proves not to accurately reflect the strength and consistency of the solar radiance, the assumptions underlying the financial projections as to the amount of electricity to be generated by the facility may be different and cash could be impacted.
For certain of its development projects, the Company relies on financing from third party tax equity investors. These investors typically provide funding upon commercial operation of the facility. Should certain facilities not meet the conditions required for tax equity funding, expected returns from the facilities may be impacted.

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Litigation Risks and Other Contingencies
APUC and certain of its subsidiaries are involved in various 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 $345 million and punitive damages in the sum of $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.
APUC believes that the claims are without merit, and intends to vigorously defend the action.
See further discussion of claims made by or against APUC or its subsidiaries in Regulatory Risk.
Cybersecurity Risk
The Company’s information technology systems may be vulnerable to potential risks from cybersecurity attacks. Attacks can be caused by malware, viruses, email attachments, acts of war or terrorism and can originate from individuals from both inside and outside the organization. An attack could result in service disruptions, system failures, the disclosure of personal customer and employee information, and could lead to an adverse effect on the Company’s financial performance. A breach of personal or confidential information may also occur as a result of non-cyber means, such as breach of physical security and device theft. Should a material breach occur the Company may not be able to recover all costs and losses through insurance, legal or regulatory processes.
Energy Consumption and Advancement in Technologies Risk
The Liberty Utilities Group’s operations are subject to changes in demand for energy which are impacted by general economic conditions, customer’s focus on energy efficiency, and advancements in new technologies.
The Liberty Utilities Group is actively involved in working with governments and customers to ensure these changes in consumption do not negatively impact the services provided. Furthermore, through its strategic initiatives the Liberty Utilities Group is constantly looking for ways to maintain the Company’s competitive advantage.
Uninsured Risk
The Company maintains insurance for accidental loss and potential liabilities to third parties in accordance with the industry practice. However, there are certain elements of the Liberty Utilities Group’s regulated utilities that are not fully insured as the cost of the coverage is not economically viable. In the event that a liability event or loss is not covered through insurance the Liberty Utilities Group would apply to their respective regulator to request recovery through increased customer rates. Cost recovery through this mechanism is subject to regulatory approval and is therefore uncertain.
Insurance coverage for the rest of the Company is also subject to policy conditions and exclusions, coverage limits, and various deductibles, and not all types of liabilities and losses may be covered by insurance, in which case the Company may be financially exposed.

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QUARTERLY FINANCIAL INFORMATION
The following is a summary of unaudited quarterly financial information for the eight quarters ended December 31, 2018:

(all dollar amounts in $ millions except per share information) |  | 1st Quarter 2018 |  |  | 2nd Quarter 2018 |  |  | 3rd Quarter 2018 |  |  | 4th Quarter 2018 |
Revenue |  | $ | 494.8 |  |  | $ | 366.2 |  |  | $ | 366.5 |  |  | $ | 419.9 |
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 |
Adjusted Net Earnings1 |  |  | 141.1 |  |  |  | 50.9 |  |  |  | 49.7 |  |  |  | 70.5 |
Adjusted Net Earnings per share1 |  |  | 0.30 |  |  |  | 0.11 |  |  |  | 0.10 |  |  |  | 0.14 |
Adjusted EBITDA1 |  |  | 279.2 |  |  |  | 160.3 |  |  |  | 166.9 |  |  |  | 196.9 |
Total assets |  |  | 8,941.8 |  |  |  | 8,920.7 |  |  |  | 9,072.6 |  |  |  | 9,389.0 |
Long term debt2 |  |  | 3,832.7 |  |  |  | 3,448.1 |  |  |  | 3,561.3 |  |  |  | 3,337.3 |
Dividend declared per common share |  | $ | 0.12 |  |  | $ | 0.13 |  |  | $ | 0.13 |  |  | $ | 0.13 |

|  | 1st Quarter 2017 |  |  | 2nd Quarter 2017 |  |  | 3rd Quarter 2017 |  |  | 4th Quarter 2017 |
Revenue |  | $ | 421.7 |  |  | $ | 337.0 |  |  | $ | 353.7 |  |  | $ | 409.5 |
Net earnings attributable to shareholders |  |  | 19.3 |  |  |  | 35.3 |  |  |  | 47.7 |  |  |  | 47.2 |
Net earnings per share |  |  | 0.05 |  |  |  | 0.09 |  |  |  | 0.12 |  |  |  | 0.11 |
Adjusted Net Earnings1 |  |  | 66.5 |  |  |  | 39.5 |  |  |  | 52.0 |  |  |  | 67.0 |
Adjusted Net Earnings per share1 |  |  | 0.19 |  |  |  | 0.09 |  |  |  | 0.13 |  |  |  | 0.16 |
Adjusted EBITDA1 |  |  | 192.3 |  |  |  | 147.1 |  |  |  | 164.2 |  |  |  | 185.8 |
Total assets |  |  | 8,174.9 |  |  |  | 8,113.3 |  |  |  | 8,258.6 |  |  |  | 8,395.6 |
Long term debt2 |  |  | 3,586.5 |  |  |  | 3,404.5 |  |  |  | 3,553.7 |  |  |  | 3,080.5 |
Dividend declared per common share |  | $ | 0.12 |  |  | $ | 0.12 |  |  | $ | 0.12 |  |  | $ | 0.12 |

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 $337 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. 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 $65.5 million over the prior two year period. Earnings have been significantly impacted by non-cash factors such as deferred tax recovery and expense, impairment of intangibles, property, plant and equipment and mark-to-market gains and losses on financial instruments.

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SUMMARY FINANCIAL INFORMATION OF ATLANTICA
The Company has a 41.5% interest in the common stock of 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, 2018 and 2017 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) | 2018 |  | 2017 |
Revenue | $ | 1,043.8 |  | $ | 1,008.4 |
Profit (loss) for the year |  | 55.3 |  |  | (104.9 | )
Total non-current assets |  | 8,791.3 |  |  | 9,350.4 |
Total current assets |  | 1,127.7 |  |  | 1,141.9 |
Total non-current liabilities |  | 7,423.8 |  |  | 8,096.5 |
Total current liabilities |  | 739.1 |  |  | 500.4 |

DISCLOSURE CONTROLS AND PROCEDURES
APUC’s management carried out an evaluation as of December 31, 2018, 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, 2018, APUC’s disclosure controls and procedures are effective to provide reasonable assurance that information required to be disclosed by APUC in reports that it files or submits under the Exchange Act is recorded, processed, summarized, and reported within the time periods specified in SEC rules and forms, and is accumulated and communicated to management, including the CEO and CFO, as appropriate, to allow timely decisions regarding required disclosure.
MANAGEMENT REPORT ON INTERNAL CONTROLS OVER FINANCIAL REPORTING
Management, including the CEO and CFO, is responsible for establishing and maintaining adequate internal control over financial reporting (as defined in Rules 13a-15(f) and 15d-15(f) under the Exchange Act) to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with U.S. GAAP.
The Company’s internal control over financial reporting framework includes those policies and procedures that (i) pertain to the maintenance of records that, in reasonable detail, accurately and fairly reflect the transactions and dispositions of the assets of the Company; (ii) provide reasonable assurance that transactions are recorded as necessary to permit preparation of financial statements in accordance with U.S. GAAP, and that receipts and expenditures of the Company are being made only in accordance with authorizations of management and directors of the Company; and (iii) provide reasonable assurance regarding prevention or timely detection of unauthorized acquisition, use or disposition of the Company’s assets that could have a material effect on the Company’s consolidated financial statements.
Due to its inherent limitations, internal control over financial reporting may not prevent or detect all misstatements. Further, the effectiveness of internal control is subject to the risk that controls may become inadequate because of changes in conditions, or that the degree of compliance with policies or procedures may change.
Management assessed the effectiveness of the Company’s internal control over financial reporting as of December 31, 2018, based on the framework established in Internal Control - Integrated Framework (2013) issued by the Committee of Sponsoring Organizations of the Treadway Commission (COSO). This assessment included review of the documentation of controls, evaluation of the design effectiveness of controls, testing of the operating effectiveness of controls, and a conclusion on this evaluation. Based on this assessment, management concluded that the Company’s internal control over financial reporting was effective as of December 31, 2018 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, 2018, there has been no change in the Company’s internal control over financial reporting that has materially affected, or is reasonably likely to materially affect, the Company’s internal control over financial reporting.

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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 to the consolidated financial statements, respectively. Management believes the following accounting policies involve the application of critical accounting estimates. Accordingly, these accounting estimates have been reviewed and discussed with the Audit Committee of the Board of Directors of APUC.
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, 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 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 2018 and 2017, Management assessed qualitative and quantitative factors for each of the reporting units that were allocated goodwill. No goodwill impairment provision was required.
Measurement of Deferred Taxes
On December 22, 2017, the U.S. government enacted the Tax Cuts and Jobs Act (the “Act”). The Act made broad and complex changes to the U.S. tax code which impacted 2017 including, but not limited to, reducing the U.S. federal corporate tax rate from 35% to 21% and introducing 100% expensing for certain capital expenditures, excluding regulated utilities, made after September 27, 2017. Management’s judgment is required to measure the deferred taxes assets and liabilities at the enactment date based on these changes. Where requirements of the implementation of the new Act are incomplete, management uses judgments and assumptions to calculate a reasonable provisional amount to include in the Company’s financial statements.

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Valuation of Deferred Tax Assets
In assessing the realization of deferred tax assets, management considers whether it is more likely than not that some portion or all of the deferred tax assets will not be realized and provides any necessary valuation allowances as required. Management evaluates the probability of realizing deferred tax assets by reviewing a forecast of future taxable income together with Management’s intent and ability to implement tax planning strategies, if necessary, to realize deferred tax assets. Although at this time Management considers it more likely than not that it will have sufficient taxable income to realize the deferred tax assets, there can be no assurance that the Company will generate sufficient taxable income in the future to utilize these deferred tax assets. Management also assesses the ability to utilize tax attributes, including those in the form of carryforwards, for which the benefits have already been reflected in the financial statements. Management’s assessment has been impacted by the tax reform discussed above.
Accounting for Rate Regulation
Accounting guidance for regulated operations provides that rate-regulated entities account for and report assets and liabilities consistent with the recovery of those incurred costs in rates if the rates established are designed to recover the costs of providing the regulated service and if the competitive environment makes it probable that such rates can be charged and collected. This accounting guidance is applied to the Liberty Utilities Group’s operations.
Certain expenses and revenues subject to utility regulation or rate determination normally reflected in income are deferred on the balance sheet as regulatory assets or liabilities and are recognized in income as the related amounts are included in service rates and recovered from or refunded to customers. Regulatory assets and liabilities are recorded when it is probable that these items will be recovered or reflected in future rates. Determining probability requires significant judgment on the part of management and includes, but is not limited to, consideration of testimony presented in regulatory hearings, proposed regulatory decisions, final regulatory orders and industry practice. If events were to occur that would make the recovery of these assets and liabilities no longer probable, these regulatory assets and liabilities would be required to be written off or written down.
Unbilled Energy Revenues
Revenues related to natural gas, electricity and water delivery are generally recognized upon delivery to customers. The determination of customer billings is based on a systematic reading of meters throughout the month. At the end of each month, amounts of natural gas, energy or water provided to customers since the date of the last meter reading are estimated, and the corresponding unbilled revenue is recorded. Factors that can impact the estimate of unbilled energy include, but are not limited to, seasonal weather patterns compared to normal, total volumes supplied to the system, line losses, economic impacts, and composition of customer classes. Estimates are reversed in the following month and actual revenue is recorded based on subsequent meter readings.
The Financial Accounting Standards Board (“FASB”) issued a revenue recognition standard codified as ASC 606, Revenue from Contracts with Customers. The Company adopted the new standard using the modified retrospective method effective January 1, 2018. The adoption of Topic 606 did not have a material impact on the consolidated financial statements and the pattern of revenue recognition.
Derivatives
APUC uses derivative instruments to manage exposure to changes in commodity prices, foreign exchange rates, and interest rates. Management’s judgment is required to determine if a transaction meets the definition of a derivative and, if it does, whether the normal purchases and sales exception applies or whether individual transactions qualify for hedge accounting treatment. Management’s judgment is also required to determine the fair value of derivative transactions. APUC determines the fair value of derivative instruments based on forward market prices in active markets obtained from external parties adjusted for nonperformance risk. A significant change in estimate could affect APUC’s results of operations if the hedging relationship was considered no longer effective.
Pension and Post-employment Benefits
The obligations and related costs of defined benefit pension and post-employment benefit plans are calculated using actuarial concepts, which include critical assumptions related to the discount rate, mortality rate, compensation increase, expected rate of return on plan assets and medical cost trend rates. These assumptions are important elements of expense and/or liability measurement and are updated on an annual basis, or upon the occurrence of significant events. The Company used the new mortality improvement scale (MP-2018) recently released by the Society of Actuaries adjusted to reflect the 2018 Social Security Administration ultimate improvement rates.
The FASB issued ASU 2017-07 Compensation—Retirement Benefits (Topic 715): Improving the Presentation of Net Periodic Pension Cost and Net Periodic Post-retirement Benefit Cost, for reporting of defined benefit pension cost and post-retirement benefit cost (“net benefit cost”) in the financial statements. The Company adopted this guidance effective January 1, 2018. Following the effective date of this Accounting Standards Update (“ASU”), the Company’s regulated operations only capitalize the service costs component and therefore no regulatory to U.S. GAAP reporting differences exist. The Company has applied the practical expedient for retrospective application on the statement of operations.

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Sensitivities
The sensitivities of key assumptions used in measuring accrued benefit obligations and benefit plan cost for 2018 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.

|  | 2018 Pension Plans |  |  | 2018 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 |  |  | (43.9 | ) |  |  | (4.1 | ) |  |  | (22.8 | ) |  |  | (1.0 | )
1% decrease |  |  | 53.6 |  |  |  | 3.9 |  |  |  | 29.0 |  |  |  | 2.5 |
Future compensation rate |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |
1% increase |  |  | 0.3 |  |  |  | 0.6 |  |  |  | — |  |  |  | — |
1% decrease |  |  | (0.3 | ) |  |  | (2.7 | ) |  |  | — |  |  |  | — |
Expected return on plan assets |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |
1% increase |  |  | — |  |  |  | (3.5 | ) |  |  | — |  |  |  | (1.2 | )
1% decrease |  |  | — |  |  |  | 3.5 |  |  |  | — |  |  |  | 1.4 |
Life expectancy |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |
10% increase |  |  | 26.1 |  |  |  | 2.8 |  |  |  | 15.1 |  |  |  | 1.8 |
10% decrease |  |  | (27.7 | ) |  |  | (4.0 | ) |  |  | (14.5 | ) |  |  | (1.4 | )
Health care trend |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |
1% increase |  |  | — |  |  |  | — |  |  |  | 28.0 |  |  |  | 4.4 |
1% decrease |  |  | — |  |  |  | — |  |  |  | (22.2 | ) |  |  | (2.6 | )

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

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