EX-99.2 3 a2018q3-exhibit992xmda.htm EXHIBIT 99.2 Q3 2018 MD&A
Exhibit 99.2
Management Discussion & Analysis
(All monetary amounts are in thousands of U.S. dollars, except where otherwise noted.)
Management of Algonquin Power & Utilities Corp. (“APUC” or the “Company” or the “Corporation”) has prepared the following discussion and analysis to provide information to assist its shareholders’ understanding of the financial results for the three and nine months ended September 30, 2018. This Management Discussion & Analysis (“MD&A”) should be read in conjunction with APUC’s unaudited consolidated financial statements for the three and nine months ended September 30, 2018 and 2017. The MD&A should also be read in conjunction with APUC's annual audited financial statements for the years ended December 31, 2017 and 2016, and the annual MD&A for the year ended December 31, 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 quarters ended September 30, 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.
Effective January 1, 2018, the Company elected to change its presentation currency from the Canadian dollar (“Cdn” or “C$”) to the United States dollar (“U.S.$” or “$”). As such, APUC's interim and annual consolidated financial statements will be reported in U.S. dollars. The Company applied the change to a U.S. dollar presentation currency retrospectively and restated the comparative financial information as if the new presentation currency had always been the Company’s presentation currency. As a result, all dollar amounts in this MD&A are expressed in U.S. dollars, unless otherwise specified. See the Critical Accounting Estimates and Policies section of this MD&A for further information.
This MD&A is based on information available to management as of November 8, 2018.
Contents

Caution Concerning Forward-Looking Statements, Forward-Looking Information and non-GAAP Measures | 2
Overview and Business Strategy | 5
Major Highlights | 6
2018 Third Quarter Results From Operations | 7
2018 Year-to-Date Results From Operations | 9
2018 Adjusted EBITDA Summary | 11
Liberty Power Group | 12
Liberty Utilities Group | 18
Corporate Development Activities | 23
APUC: Corporate and Other Expenses | 26
Non-GAAP Financial Measures | 28
Summary of Property, Plant, and Equipment Expenditures | 30
Liquidity and Capital Reserves | 32
Share-Based Compensation Plans | 35
Related Party Transactions | 36
Enterprise Risk Management | 37
Quarterly Financial Information | 41
Disclosure Controls and Internal Controls Over Financial Reporting | 41
Critical Accounting Estimates and Policies | 42

Caution Concerning Forward-looking Statements, Forward-looking Information and non-GAAP Measures
Forward-looking Statements and Forward-Looking Information
This document may contain statements that constitute "forward-looking statements" or "forward-looking information" within the meaning of applicable securities legislation (collectively, “forward-looking information”). The words “anticipates”, “believes”, “budget”, “could”, “estimates”, “expects”, “forecasts”, “intends”, “may”, “might”, “plans”, “projects”, “schedule”, “should”, “will”, “would” and similar expressions are often intended to identify forward-looking information, although not all forward-looking information contains these identifying words. Specific forward-looking information in this document includes, but are not limited to, statements relating to: expected future growth and results of operations; liquidity, capital resources and operational requirements; rate cases, including resulting decisions and rates and expected impacts and timing; sources of funding, including adequacy and availability of credit facilities, debt maturation and future borrowings; 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; 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

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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 best interests; facilities being condemned or otherwise taken by governmental entities; increased external stakeholder activism adverse to the Corporation’s interests; and fluctuations in the price and liquidity of the Corporation’s Common Shares. Although the Corporation has attempted to identify important factors that could cause actual actions, events or results to differ materially from those described in forward-looking information, there may be other factors that cause actions, events or results not to be as anticipated, estimated or intended. Some of these and other factors are discussed in more detail under the heading “Enterprise Risk Management” and in the Corporation's most recent AIF.
Forward-looking information contained herein is made as of the date of this document and based on the plans, beliefs, estimates, projections, expectations, opinions and assumptions of management on the date hereof. There can be no assurance that forward-looking information will prove to be accurate, as actual results and future events could differ materially from those anticipated in such forward-looking information. Accordingly, readers should not place undue reliance on forward-looking information. While subsequent events and developments may cause the Corporation’s views to change, the Corporation disclaims any obligation to update any forward-looking information or to explain any material difference between subsequent actual events and such forward-looking information, except to the extent required by law. All forward-looking information contained herein is qualified by these cautionary statements.
Non-GAAP Financial Measures
The terms “Adjusted Net Earnings”, “Adjusted Earnings Before Interest, Taxes, Depreciation and Amortization” (“Adjusted EBITDA”), “Adjusted Funds from Operations”, "Net Energy Sales", "Net Utility Sales" and "Divisional Operating Profit" are used throughout this MD&A. The terms “Adjusted Net Earnings”, “Adjusted Funds from Operations”, "Adjusted EBITDA", "Net Energy Sales", "Net Utility Sales" and "Divisional Operating Profit" are not recognized measures under U.S. GAAP. There is no standardized measure of “Adjusted Net Earnings”, "Adjusted EBITDA", “Adjusted Funds from Operations”, "Net Energy Sales", "Net Utility Sales", and "Divisional Operating Profit"; consequently, APUC’s method of calculating these measures may differ from methods used by other companies and therefore may not be comparable to similar measures presented by other companies. A calculation and analysis of “Adjusted Net Earnings”, "Adjusted EBITDA", “Adjusted Funds from Operations”, "Net Energy Sales", "Net Utility Sales", and "Divisional Operating Profit" can be found throughout this MD&A.
Adjusted EBITDA
Adjusted EBITDA is a non-GAAP measure used by many investors to compare companies on the basis of ability to generate cash from operations. APUC uses these calculations to monitor the amount of cash generated by APUC as compared to the amount of dividends paid by APUC. APUC uses Adjusted EBITDA to assess the operating performance of APUC without the effects of (as applicable): depreciation and amortization expense, income tax expense or recoveries, acquisition costs, litigation expenses, interest expense, gain or loss on derivative financial instruments, write down of intangibles and property, plant and equipment, earnings attributable to non-controlling interests and 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. For 2017, the one-time impact of the revaluation of U.S. non-regulated net deferred income tax assets as a result of the U.S. federal corporate income tax rate reduction from 35% to 21% enacted in December 2017 is adjusted as it is also considered a non-recurring item not reflective of the performance of the underlying business of APUC. APUC believes that analysis and presentation of net earnings or loss on this basis will enhance an investor’s understanding of the operating performance of its businesses. 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, and gain or loss on foreign exchange, earnings or loss from discontinued operations and other typically non-recurring items. APUC adjusts for these factors as they may be non-cash, unusual in nature and are not factors used by management for evaluating the operating performance of the divisional units. Divisional Operating Profit is calculated inclusive of Hypothetical Liquidation at Book Value (“HLBV”) income, which represents the value of net tax attributes earned in the period from electricity generated by certain of its U.S. wind power and U.S. solar generation facilities. APUC believes that presentation of this measure will enhance an investor’s understanding of APUC’s divisional operating performance. Divisional Operating Profit is not intended to be representative of cash provided by operating activities or results of operations determined in accordance with U.S. GAAP.
Capitalized terms used herein and not otherwise defined will have the meanings assigned to them in the Company's most recent AIF.

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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 November 7, 2018, the quarterly dividend is equivalent to C$0.1679 per common share or C$0.6716 per common share per annum. APUC believes its annual dividend payout allows for both an immediate return on investment for shareholders and retention of sufficient cash within APUC to fund growth opportunities. Changes in the level of dividends paid by APUC are at the discretion of the APUC Board of Directors (the “Board”), with dividend levels being reviewed periodically by the Board in the context of cash available for distribution and earnings together with an assessment of the growth prospects available to APUC. APUC strives to achieve its results in the context of a moderate risk profile consistent with top-quartile North American power and utility operations.
APUC's operations are organized across two primary North American business units consisting of: the Liberty Power Group, which owns and operates a diversified portfolio of non-regulated renewable and thermal electric generation assets; and the Liberty Utilities Group, which owns and operates a portfolio of regulated electric, natural gas, water distribution and wastewater collection utility systems, and transmission operations. APUC also owns a 25% 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.
Liberty Power Group
The Liberty Power Group generates and sells electrical energy produced by its diverse portfolio of non-regulated renewable power generation and clean power generation facilities located across North America. The Liberty Power Group seeks to deliver continuing growth through development of new greenfield power generation projects and accretive acquisitions of additional electrical energy generation facilities.
The Liberty Power Group owns or has interests in hydroelectric, wind, solar, and thermal facilities with a combined generating capacity of approximately 1.7 GW. Approximately 86% of the electrical output from the hydroelectric, wind, and solar generating facilities is sold pursuant to long term contractual arrangements which as of September 30, 2018 had a production-weighted average remaining contract life of approximately 14 years.
Liberty Utilities Group
The Liberty Utilities Group operates a diversified portfolio of regulated utility systems throughout the United States serving approximately 766,000 connections. The Liberty Utilities Group provides safe, high quality, and reliable services to its customers and seeks to deliver stable and predictable earnings to APUC. In addition to encouraging and supporting organic growth within its service territories, the Liberty Utilities Group seeks to deliver continued growth in earnings through accretive 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. The electric utility systems in total serve approximately 265,000 electric connections and also operate generation assets with a net capacity of approximately 1.4 GW.
The Liberty Utilities Group's regulated natural gas distribution utility systems are located in the States of Georgia, Illinois, Iowa, Massachusetts, New Hampshire and Missouri serving approximately 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 163,000 connections.
Corporate Development
The Company's development activities will be undertaken primarily by Abengoa-Algonquin Global Energy Solutions ("AAGES"), a newly formed joint venture with Abengoa S.A (MC: ABG) ("Abengoa"), an international infrastructure construction company. AAGES works with a global reach to identify, develop, and construct new renewable power generating facilities and water infrastructure assets. Once a project developed by AAGES has reached commercial operation, 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. Complementing the formation of AAGES, APUC has acquired a 25% interest in Atlantica Yield plc (NASDAQ: AY) ("Atlantica") and has agreed to acquire an additional 16.5% interest in Atlantica from Abengoa, bringing APUC’s investment in Atlantica to 41.5%. This investment provides the Company with immediate accretion from an investment in a portfolio of high quality international clean energy and water infrastructure assets under long term contracts with high quality counterparties. More strategically, Atlantica represents a potential location into which AAGES’ international development projects may be held after commercial operations are achieved.

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Major Highlights
Corporate Highlights
Operating Results
APUC operating results compared to the same period last year.

(all dollar amounts in $ millions except per share information) | Three Months Ended September 30 |  | Nine Months Ended September 30
2018 |  | 2017 |  | Change |  | 2018 |  | 2017 |  | Change
Net earnings attributable to shareholders | $57.9 |  | $47.7 |  | 21% |  | $141.0 |  | $102.3 |  | 38%
Adjusted Net Earnings 1 | $49.7 |  | $52.0 |  | (4)% |  | $241.6 |  | $158.0 |  | 53%
Adjusted EBITDA 1 | $164.2 |  | $157.7 |  | 4% |  | $603.7 |  | $497.1 |  | 21%
Net earnings per common share | $0.12 |  | $0.12 |  | —% |  | $0.30 |  | $0.26 |  | 15%
Adjusted Net Earnings per common share 1 | $0.10 |  | $0.13 |  | (23)% |  | $0.52 |  | $0.41 |  | 27%

1 | See Non-GAAP Financial Measures

Declaration of 2018 Fourth Quarter Dividend of $0.1282 (C$0.1679) per Common Share
APUC currently targets an industry leading annual growth in dividends payable to shareholders underpinned by increases in earnings and cashflow. Management believes that the increase in dividends is consistent with APUC's stated strategy of delivering total shareholder return comprised of an attractive current dividend yield and capital appreciation.
On November 8, 2018, APUC announced that the Board of APUC declared a fourth quarter 2018 dividend of $0.1282 per common share payable on January 15, 2019 to shareholders of record on December 31, 2018. Based on the Bank of Canada exchange rate on November 7, 2018, the Canadian dollar equivalent for the fourth quarter 2018 dividend is set at C$0.1679 per common share.
The previous four quarter equivalent Canadian dollar dividends per common share have been as follows:

| Q1 2018 | Q2 2018 | Q3 2018 | Q4 2018 | Total
U.S. dollar dividend | $0.1165 | $0.1282 | $0.1282 | $0.1282 | $0.5011
Canadian dollar equivalent | $0.1492 | $0.1648 | $0.1673 | $0.1679 | $0.6492

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).
Investment in Atlantica
On April 17, 2018, APUC announced that it had entered into an agreement with an entity related to Abengoa, S.A ("Abengoa") to purchase an additional 16.5% equity interest in Atlantica Yield plc ("Atlantica") for a total purchase price of approximately $345 million, based on a price of $20.90 per ordinary share of Atlantica. The closing of this transaction is expected to be completed in the fourth quarter of 2018. With this additional investment, APUC will own approximately 41.5% of Atlantica.
Fitch Assigns First-Time Ratings to Algonquin Power & Utilities Corp. and Subsidiaries
On July 20, 2018, Fitch Ratings, Inc. ("Fitch") assigned a BBB (flat) Long-Term Issuer Default Rating ("IDR") and an F2 Short-Term IDR to APUC and Liberty Utilities Co., the parent company for the Liberty Utilities Group. Fitch assigned a BBB (flat) 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 (high) rating to the senior unsecured debt issued by Liberty Utilities Finance GP1 ("Liberty Finance"), a special purpose financing entity of Liberty Utilities Co.
Liberty Utilities Group Highlights
Progress Made on "Greening of the Fleet"
In 2017, The Empire District Electric Company ("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 expand its wind generating

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capacity with the development of additional wind generation in or near its service territory that will utilize all available Production Tax Credits. The plan forecasts cost savings for customers of $172.0 - $325.0 million over a twenty-year period.
On July 12, 2018, Empire received an order from the Missouri Public Service Commission (“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”.
On October 18, 2018, Empire filed with the MPSC a request for approval of the Certificate of Convenience and Necessity (“CCN”) for 300 MW of the 600 MW contemplated as part of the initiative. A proposed procedural schedule has been filed requesting an MPSC Order be issued no later than April 30, 2019. Empire is anticipated to file a CCN for the remaining 300 MW during the fourth quarter of 2018.
2018 Third Quarter Results From Operations

Key Financial Information | Three Months Ended September 30
(all dollar amounts in $ millions except per share information) | 2018 |  | 2017
Revenue | $ | 366.5 |  |  | $ | 353.7 |
Net earnings attributable to shareholders | 57.9 |  |  | 47.7 |
Cash provided by operating activities | 131.5 |  |  | 98.4 |
Adjusted Net Earnings 1 | 49.7 |  |  | 52.0 |
Adjusted EBITDA 1 | 164.2 |  |  | 157.7 |
Adjusted Funds from Operations 1 | 127.7 |  |  | 104.3 |
Dividends declared to common shareholders | 61.0 |  |  | 45.3 |
Weighted average number of common shares outstanding | 473,774,957 |  |  | 386,816,307 |
Per share |  |  |
Basic net earnings | $ | 0.12 |  |  | $ | 0.12 |
Diluted net earnings | $ | 0.12 |  |  | $ | 0.12 |
Adjusted Net Earnings 1,2 | $ | 0.10 |  |  | $ | 0.13 |
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 September 30, 2018, APUC experienced an average exchange rate of Canadian to U.S. dollar of approximately 0.7652 as compared to 0.7983 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 September 30, 2018, APUC's Canadian entities represented approximately 5% of APUC consolidated Adjusted EBITDA.
For the three months ended September 30, 2018, APUC reported total revenue of $366.5 million as compared to $353.7 million during the same period in 2017, an increase of $12.8 million. The major factors resulting in the increase in APUC revenue in the three months ended September 30, 2018 as compared to the corresponding period in 2017 are set out as follows:

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(all dollar amounts in $ millions) | Three Months Ended September 30
Comparative Prior Period Revenue | $ | 353.7 |
LIBERTY POWER GROUP |
Existing Facilities |
Hydro: Decrease is primarily due to lower production at the Ontario, Maritimes and Quebec Region Facilities partially offset by favourable rates and higher production in the Western Region. | (0.8 | )
Wind U.S.: Increase is primarily due to higher production and favourable market rates at the Minonk Wind Facility. | 1.5 |
Wind Canada: Increase is primarily due to higher production. | 0.3 |
Solar U.S.: Increase is primarily due to higher production. | 0.2 |
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. | 4.1 |
Other: | 0.1 |
| 5.4 |
New Facilities |
Solar U.S.: Great Bay Solar achieved full commercial operations ("COD") in March 2018. | 2.4 |
| 2.4 |
Foreign Exchange | (0.7 | )
LIBERTY UTILITIES GROUP |
Existing Facilities |
Electricity: Increase is primarily due to higher cooling degree days, which resulted in higher consumption at the Empire Electric System. | 9.6 |
Gas: Decrease is primarily due to lower consumption. | (0.7 | )
Water: Decrease is primarily due to transition services that were provided in 2017 associated with the disposition of the Mountain Water System, partially offset by higher consumption at the Arizona Water Systems. | (0.7 | )
Other: | (0.2 | )
| 8.0 |
Rate Reviews |
Electricity: Implementation of lower rates at the Empire and Granite State Electric Systems due to the effects of the Tax Cuts and Jobs Act ("U.S. Tax Reform"). | (1.4 | )
Gas: Implementation of lower rates at the EnergyNorth and Peach State Gas Systems due to U.S. Tax Reform, partially offset by rate increases at the Midstates Gas System. | (0.3 | )
Water: Implementation of lower rates at the Arizona and Park Water Systems due to U.S. Tax Reform, partially offset by rate increases at the Litchfield Park Water System. | (0.6 | )
| (2.3 | )
Current Period Revenue | $ | 366.5 |

A more detailed discussion of these factors is presented within the business unit analysis.
For the three months ended September 30, 2018, net earnings attributable to shareholders totaled $57.9 million as compared to $47.7 million during the same period in 2017, an increase of $10.2 million or 21.4%. The increase was due to a $1.4 million increase in earnings from operating facilities, a $10.0 million gain due to change in fair value of an investment carried at fair value, a $9.4 million increase in interest, dividend, equity and other income, a $1.7 million decrease in foreign exchange loss, a $0.2 million decrease in pension and post-employment non-service costs, and a $1.0 million decrease in income tax expense (tax explanations are discussed in APUC: Corporate and Other Expenses). These items were partially offset by a $6.6 million increase in depreciation and amortization expenses, a $1.3 million increase in other losses, a $3.4 million decrease in net effect of non-controlling interests, a $0.7 million increase in loss from derivative instruments, and a $1.5 million increase in interest expense as compared to the same period in 2017.

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During the three months ended September 30, 2018, cash provided by operating activities totaled $131.5 million as compared to cash provided by operating activities of $98.4 million during the same period in 2017. During the three months ended September 30, 2018, Adjusted Funds from Operations, a Non-GAAP measure, totaled $127.7 million compared to Adjusted Funds from Operations of $104.3 million during the same period in 2017. The increase in Adjusted Funds from Operations is primarily due to the timing of pension contributions as well as a one-time contribution of approximately $9.0 million to the pension plan in 2017 to reduce the Company's defined benefit pension obligations.
During the three months ended September 30, 2018, Adjusted EBITDA totaled $164.2 million as compared to $157.7 million during the same period in 2017, an increase of $6.5 million or 4.1%. 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 Year-To-Date Results From Operations

Key Financial Information | Nine Months Ended September 30
(all dollar amounts in $ millions except per share information) | 2018 |  | 2017
Revenue | $ | 1,227.5 |  |  | $ | 1,112.5 |
Net earnings attributable to shareholders | 141.0 |  |  | 102.3 |
Cash provided by operating activities | 361.7 |  |  | 210.6 |
Adjusted Net Earnings 1 | 241.6 |  |  | 158.0 |
Adjusted EBITDA 1 | 603.7 |  |  | 497.1 |
Adjusted Funds from Operations 1 | 421.6 |  |  | 351.1 |
Dividends declared to common shareholders | 172.4 |  |  | 135.4 |
Weighted average number of common shares outstanding | 456,551,230 |  |  | 372,109,455 |
Per share |  |  |
Basic net earnings | $ | 0.30 |  |  | $ | 0.26 |
Diluted net earnings | $ | 0.29 |  |  | $ | 0.26 |
Adjusted Net Earnings 1,2 | $ | 0.52 |  |  | $ | 0.41 |
Dividends declared to common shareholders | $ | 0.37 |  |  | $ | 0.35 |
| As at
| September 30, 2018 |  | December 31, 2017
Total assets | 9,072.6 |  |  | 8,397.4 |
Long term debt 3 | 3,561.3 |  |  | 3,080.5 |

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

For the nine months ended September 30, 2018, APUC experienced an average exchange rate of Canadian to U.S. dollar of approximately 0.7766 as compared to 0.7652 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 nine months ended September 30, 2018, APUC's Canadian entities represented approximately 5% of APUC consolidated Adjusted EBITDA.
For the nine months ended September 30, 2018, APUC reported total revenue of $1,227.5 million as compared to $1,112.5 million during the same period in 2017, an increase of $115.0 million or 10.3%. The major factors resulting in the increase in APUC revenue for the nine months ended September 30, 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) | Nine Months Ended September 30
Comparative Prior Period Revenue | $ | 1,112.5 |
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. | (3.4 | )
Wind Canada: Increase is primarily due to annual rate increases, partially offset by lower overall production. | 0.2 |
Wind U.S.: Decrease is primarily due to lower production and unfavourable market rates at the Senate Wind Facility. | (2.7 | )
Solar Canada: Increase is primarily due to higher production. | 0.2 |
Solar U.S.: Increase is primarily due to higher production. | 0.3 |
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. | 10.9 |
Other: | 0.1 |
| 5.6 |
New Facilities |
Wind U.S.: Acquisition of Deerfield Wind Facility in March 2017. | 6.6 |
Solar U.S.: Great Bay Solar achieved full COD in March 2018. | 5.9 |
| 12.5 |
Foreign Exchange | 1.0 |
LIBERTY UTILITIES GROUP |
Existing Facilities |
Electricity: Increase is primarily due to higher heating degree days in the first quarter and higher cooling degree days in the second and third quarters of the year, which resulted in higher consumption and pass through commodity costs at the Empire Electric System. | 60.7 |
Gas: Increase is primarily related to favourable weather resulting in higher consumption and higher pass through commodity costs at the Midstates, EnergyNorth, New England and Empire Gas Systems. | 42.9 |
Water: Decrease is primarily due to divestiture of the Mountain Water System from condemnation proceedings on June 22, 2017. | (9.9 | )
Other: | (0.3 | )
| 93.4 |
Rate Reviews |
Electricity: Implementation of new rates at the Granite State, Empire and Calpeco Electric Systems partially offset by lower rates due to U.S. Tax Reform. | 0.8 |
Gas: Implementation of new rates at the Midstates Gas System, partially offset by lower rates at the EnergyNorth and Peach State Gas Systems due to U.S. Tax Reform. | 2.3 |
Water: Implementation of lower rates at the Arizona and Park Water Systems due to U.S. Tax Reform, partially offset by rate increases at the Litchfield Park Water System. | (0.6 | )
| 2.5 |
Current Period Revenue | $ | 1,227.5 |

A more detailed discussion of these factors is presented within the business unit analysis.
For the nine months ended September 30, 2018, net earnings attributable to shareholders totaled $141.0 million as compared to $102.3 million during the same period in 2017, an increase of $38.7 million or 37.8%. The increase was due to a $22.1 million increase in earnings from operating facilities, a $26.5 million increase in interest, dividend, equity and other income, a $57.9 million increase in net effect of non-controlling interests, a $10.7 million decrease in interest expense, a $4.0 million decrease in pension and post-employment non-service costs, a $37.1 million decrease in acquisition costs, and a $0.3 million

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

decrease in loss from derivative instruments. These items were partially offset by a $2.8 million increase in administration charges, a $14.8 million increase in depreciation and amortization expenses, a $0.1 million decrease in foreign exchange gains, a $91.9 million loss due to change in fair value of an investment carried at fair value, a $3.4 million decrease in other gains, and a $6.9 million increase in income tax expense (tax explanations are discussed in APUC: Corporate and Other Expenses) as compared to the same period in 2017.
During the nine months ended September 30, 2018, cash provided by operating activities totaled $361.7 million as compared to $210.6 million during the same period in 2017. During the nine months ended September 30, 2018, Adjusted Funds from Operations, a non-GAAP measure, totaled $421.6 million as compared to Adjusted Funds from Operations of $351.1 million the same period in 2017, an increase of $70.5 million.
Adjusted EBITDA in the nine months ended September 30, 2018 totaled $603.7 million as compared to $497.1 million during the same period in 2017, an increase of $106.6 million or 21.4%. 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 September 30, 2018 totaled $164.2 million as compared to $157.7 million during the same period in 2017, an increase of $6.5 million or 4.1%. Adjusted EBITDA for the nine months ended September 30, 2018 totaled $603.7 million as compared to $497.1 million during the same period in 2017, an increase of $106.6 million or 21.4%. 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 September 30 |  | Nine Months Ended September 30
(all dollar amounts in $ millions) | 2018 |  | 2017 |  | 2018 |  | 2017
Liberty Power Group Operating Profit | $ | 43.8 |  |  | $ | 35.1 |  |  | $ | 226.7 |  |  | $ | 137.1 |
Liberty Utilities Group Operating Profit | 134.8 |  |  | 135.7 |  |  | 417.5 |  |  | 399.7 |
Administrative Expenses | (11.5 | ) |  | (11.5 | ) |  | (37.7 | ) |  | (34.9 | )
Other Income & Expenses | (2.9 | ) |  | (1.6 | ) |  | (2.8 | ) |  | (4.8 | )
Total Algonquin Power & Utilities Adjusted EBITDA | $ | 164.2 |  |  | $ | 157.7 |  |  | $ | 603.7 |  |  | $ | 497.1 |
Change in Adjusted EBITDA ($) | $ | 6.5 |  |  |  |  | $ | 106.6 |  |  |
Change in Adjusted EBITDA (%) | 4.1 | % |  |  |  | 21.4 | % |  |

Change in Adjusted EBITDA | Three Months Ended September 30, 2018
(all dollar amounts in $ millions) | Power | Utilities | Corporate | Total
Prior period balances | $ | 35.1 |  | $ | 135.7 |  | $ | (13.1 | ) | $ | 157.7 |
Existing Facilities | (2.9 | ) | 1.4 |  | (1.3 | ) | (2.8 | )
New Facilities | 12.0 |  | — |  | — |  | 12.0 |
Rate Reviews | — |  | (2.3 | ) | — |  | (2.3 | )
Foreign Exchange Impact | (0.4 | ) | — |  | — |  | (0.4 | )
Administrative Expenses | — |  | — |  | — |  | — |
Total change during the period | $ | 8.7 |  | $ | (0.9 | ) | $ | (1.3 | ) | $ | 6.5 |
Current period balances | $ | 43.8 |  | $ | 134.8 |  | $ | (14.4 | ) | $ | 164.2 |

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

Change in Adjusted EBITDA | Nine Months Ended September 30, 2018
(all dollar amounts in $ millions) | Power | Utilities | Corporate | Total
Prior period balances | $ | 137.1 |  | $ | 399.7 |  | $ | (39.7 | ) | $ | 497.1 |
Existing Facilities | 48.2 |  | 15.3 |  | 2.0 |  | 65.5 |
New Facilities | 40.5 |  | — |  | — |  | 40.5 |
Rate Reviews | — |  | 2.5 |  | — |  | 2.5 |
Foreign Exchange Impact | 0.9 |  | — |  | — |  | 0.9 |
Administration Expenses | — |  | — |  | (2.8 | ) | (2.8 | )
Total change during the period | $ | 89.6 |  | $ | 17.8 |  | $ | (0.8 | ) | $ | 106.6 |
Current period balances | $ | 226.7 |  | $ | 417.5 |  | $ | (40.5 | ) | $ | 603.7 |

LIBERTY POWER GROUP
The Liberty Power Group generates and sells electrical energy produced by its diverse portfolio of non-regulated renewable power generation and clean power generation facilities located across North America. The Liberty Power Group seeks to deliver continuing growth through development of new greenfield power generation projects and accretive acquisitions of additional electrical energy generation facilities.
The Liberty Power Group owns or has interests in hydroelectric, wind, solar, and thermal facilities with a combined generating capacity of approximately 1.7 GW. Approximately 86% of the electrical output from the hydroelectric, wind, and solar generating facilities is sold pursuant to long term contractual arrangements which as of September 30, 2018 had a production-weighted average remaining contract life of approximately 14 years.
The Liberty Power Group, through its investment in Atlantica and AAGES, pursues development and construction of global clean energy and water infrastructure assets.

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

2018 Electricity Generation Performance |  |  |  |  |  |
| Long Term Average Resource |  | Three Months Ended September 30 |  | Long Term Average Resource |  | Nine Months Ended September 30
(Performance in GW-hrs sold) |  | 2018 |  | 2017 |  |  | 2018 |  | 2017
Hydro Facilities: |  |  |  |  |  |  |  |  |  |  |
Maritime Region | 20.7 |  |  | 6.3 |  |  | 12.3 |  |  | 110.6 |  |  | 76.1 |  |  | 94.8 |
Quebec Region | 62.3 |  |  | 47.7 |  |  | 55.3 |  |  | 200.7 |  |  | 190.1 |  |  | 203.1 |
Ontario Region | 26.9 |  |  | 18.7 |  |  | 28.1 |  |  | 94.2 |  |  | 75.2 |  |  | 98.9 |
Western Region | 23.8 |  |  | 18.9 |  |  | 16.1 |  |  | 52.4 |  |  | 48.6 |  |  | 49.1 |
| 133.7 |  |  | 91.6 |  |  | 111.8 |  |  | 457.9 |  |  | 390.0 |  |  | 445.9 |
Wind Facilities: |  |  |  |  |  |  |  |  |  |  |
St. Damase | 16.9 |  |  | 16.0 |  |  | 14.5 |  |  | 54.2 |  |  | 56.6 |  |  | 50.3 |
St. Leon | 87.9 |  |  | 85.3 |  |  | 84.5 |  |  | 308.8 |  |  | 293.4 |  |  | 305.5 |
Red Lily 1 | 20.4 |  |  | 17.7 |  |  | 15.7 |  |  | 64.4 |  |  | 61.3 |  |  | 62.4 |
Morse | 22.6 |  |  | 19.8 |  |  | 20.9 |  |  | 78.3 |  |  | 70.6 |  |  | 73.3 |
Amherst 2 | 43.2 |  |  | 40.0 |  |  | — |  |  | 50.6 |  |  | 47.0 |  |  | — |
Sandy Ridge | 29.9 |  |  | 21.6 |  |  | 20.8 |  |  | 114.7 |  |  | 108.4 |  |  | 111.3 |
Minonk | 128.7 |  |  | 97.1 |  |  | 82.8 |  |  | 483.9 |  |  | 437.5 |  |  | 470.2 |
Senate | 91.7 |  |  | 85.2 |  |  | 84.8 |  |  | 380.4 |  |  | 359.7 |  |  | 366.2 |
Shady Oaks | 54.5 |  |  | 50.7 |  |  | 47.2 |  |  | 255.1 |  |  | 235.1 |  |  | 256.8 |
Odell | 155.1 |  |  | 149.0 |  |  | 129.5 |  |  | 593.8 |  |  | 559.5 |  |  | 562.6 |
Deerfield 3 | 96.6 |  |  | 78.0 |  |  | 74.5 |  |  | 378.1 |  |  | 377.4 |  |  | 285.0 |
| 747.5 |  |  | 660.4 |  |  | 575.2 |  |  | 2,762.3 |  |  | 2,606.5 |  |  | 2,543.6 |
Solar Facilities: |  |  |  |  |  |  |  |  |  |  |  |  |  |
Cornwall | 4.8 |  |  | 5.4 |  |  | 5.4 |  |  | 12.5 |  |  | 12.7 |  |  | 12.3 |
Bakersfield | 25.0 |  |  | 22.8 |  |  | 20.9 |  |  | 64.2 |  |  | 60.5 |  |  | 57.8 |
Great Bay Solar 4 | 37.9 |  |  | 37.3 |  |  | — |  |  | 89.9 |  |  | 84.2 |  |  | — |
| 67.7 |  |  | 65.5 |  |  | 26.3 |  |  | 166.6 |  |  | 157.4 |  |  | 70.1 |
Renewable Energy Performance | 948.9 |  |  | 817.5 |  |  | 713.3 |  |  | 3,386.8 |  |  | 3,153.9 |  |  | 3,059.6 |
Thermal Facilities: |  |  |  |  |  |  |  |  |  |  |  |  |  |
Windsor Locks | N/A 5 |  |  | 36.5 |  |  | 31.0 |  |  | N/A 5 |  |  | 108.6 |  |  | 90.2 |
Sanger | N/A 5 |  |  | 59.5 |  |  | 18.1 |  |  | N/A 5 |  |  | 135.1 |  |  | 52.5 |
|  |  |  | 96.0 |  |  | 49.1 |  |  |  |  |  | 243.7 |  |  | 142.7 |
Total Performance |  |  |  | 913.5 |  |  | 762.4 |  |  |  |  |  | 3,397.6 |  |  | 3,202.3 |

1 | APUC owns a 75% equity interest in the Red Lily Wind Facility. The production figures represent full energy produced by the facility.
2 | APUC owns a 50% equity interest in the Amherst Wind Facility. The production figures represent full energy produced by the 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 quarter.
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 | 13

2018 Third Quarter Liberty Power Group Performance
For the three months ended September 30, 2018, the Liberty Power Group generated and sold 913.5 GW-hrs of electricity as compared to 762.4 GW-hrs during the same period of 2017.
For the three months ended September 30, 2018, the hydro facilities generated 91.6 GW-hrs of electricity as compared to 111.8 GW-hrs produced in the same period in 2017, a decrease of 18.1%. Electricity generated represented 68.5% of long-term average resources ("LTAR") as compared to 82.6% during the same period in 2017. Production in the Maritime Region was particularly impacted by high temperatures and low rainfall, with 2018 recording the lowest hydrology in over 65 years.
For the three months ended September 30, 2018, the wind facilities produced 660.4 GW-hrs of electricity as compared to 575.2 GW-hrs produced in the same period in 2017, an increase of 14.8%. During the three months ended September 30, 2018, the wind facilities (excluding Amherst) generated electricity equal to 88.1% of LTAR as compared to 81.7% during the same period in 2017.
For the three months ended September 30, 2018, the solar facilities generated 65.5 GW-hrs of electricity as compared to 26.3 GW-hrs of electricity in the same period in 2017, an increase of 149.0%. The increase in production is primarily due to the addition of the Great Bay Solar Facility. The solar facilities (excluding Great Bay Solar) production was 5.4% below its LTAR as compared to 11.7% below in the same period in 2017.
For the three months ended September 30, 2018, the thermal facilities generated 96.0 GW-hrs of electricity as compared to 49.1 GW-hrs of electricity during the same period in 2017. During the same period, the Windsor Locks Thermal Facility generated 94.5 billion lbs of steam as compared to 111.8 billion lbs of steam during the same period in 2017.
2018 Year-To-Date Liberty Power Group Performance
For the nine months ended September 30, 2018, the Liberty Power Group generated 3,397.6 GW-hrs of electricity as compared to 3,202.3 GW-hrs during the same period of 2017.
For the nine months ended September 30, 2018, the hydro facilities generated 390.0 GW-hrs of electricity as compared to 445.9 GW-hrs produced in the same period in 2017, a decrease of 12.5%. Electricity generated represented 85.2% of long-term projected average resources as compared to 95.3% during the same period in 2017. The decrease is primarily due to reduced hydrology across all hydro facilities.
For the nine months ended September 30, 2018, the wind facilities produced 2,606.5 GW-hrs of electricity as compared to 2,543.6 GW-hrs produced in the same period in 2017, an increase of 2.5%. During the nine months ended September 30, 2018, the wind facilities (excluding Amherst) generated electricity equal to 94.4% of LTAR as compared to 96.8% during the same period in 2017.
For the nine months ended September 30, 2018, the solar facilities generated 157.4 GW-hrs of electricity as compared to 70.1 GW-hrs of electricity produced in the same period in 2017, an increase of 124.5%. The increase in production is primarily due to the addition of the Great Bay Solar Facility which achieved COD on March 29, 2018. The solar facilities (excluding Great Bay Solar) production was 4.6% below its LTAR as compared to 8.6% below in the same period in 2017.
For the nine months ended September 30, 2018, the thermal facilities generated 243.7 GW-hrs of electricity as compared to 142.7 GW-hrs of electricity during the same period in 2017. During the same period, the Windsor Locks Thermal Facility generated 421.2 billion lbs of steam as compared to 422.2 billion lbs of steam during the same period in 2017.

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

2018 Liberty Power Group Operating Results |  |  |  |
| Three Months Ended September 30 |  | Nine Months Ended September 30
(all dollar amounts in $ millions) | 2018 |  | 2017 |  | 2018 |  | 2017
Revenue 1 |  |  |  |  |  |  |
Hydro | $ | 8.5 |  |  | $ | 9.3 |  |  | $ | 30.9 |  |  | $ | 33.7 |
Wind | 24.6 |  |  | 22.9 |  |  | 95.8 |  |  | 89.6 |
Solar | 6.4 |  |  | 4.2 |  |  | 14.4 |  |  | 9.2 |
Thermal | 12.7 |  |  | 8.8 |  |  | 31.9 |  |  | 21.2 |
Total Revenue | $ | 52.2 |  |  | $ | 45.2 |  |  | $ | 173.0 |  |  | $ | 153.7 |
Less: |  |  |  |  |  |  |
Cost of Sales - Energy 2 | (1.8 | ) |  | (1.6 | ) |  | (4.1 | ) |  | (3.6 | )
Cost of Sales - Thermal | (5.5 | ) |  | (2.8 | ) |  | (16.6 | ) |  | (10.0 | )
Realized gain/(loss) on hedges 3 | — |  |  | — |  |  | — |  |  | (0.6 | )
Net Energy Sales 8 | $ | 44.9 |  |  | $ | 40.8 |  |  | $ | 152.3 |  |  | $ | 139.5 |
Renewable Energy Credits 4 | 2.7 |  |  | 2.7 |  |  | 8.4 |  |  | 8.9 |
Other Revenue | 0.1 |  |  | 0.1 |  |  | 0.3 |  |  | 0.3 |
Total Net Revenue | $ | 47.7 |  |  | $ | 43.6 |  |  | $ | 161.0 |  |  | $ | 148.7 |
Expenses & Other Income |  |  |  |  |  |  |
Operating expenses | (20.3 | ) |  | (17.9 | ) |  | (57.7 | ) |  | (49.6 | )
Interest, dividend, equity and other income 5 | 11.5 |  |  | 0.6 |  |  | 29.2 |  |  | 2.0 |
HLBV income 6 | 4.9 |  |  | 8.8 |  |  | 94.2 |  |  | 36.0 |
Divisional Operating Profit 7,8 | $ | 43.8 |  |  | $ | 35.1 |  |  | $ | 226.7 |  |  | $ | 137.1 |

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 unaudited interim financial statements note 20(b)(iv).
4 | Qualifying renewable energy projects receive Renewable Energy Credits ("REC") 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 25% of the common shares (see unaudited interim financial statements note 6).
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 | 15

2018 Third Quarter Operating Results
For the three months ended September 30, 2018, the Liberty Power Group's facilities generated $43.8 million of operating profit as compared to $35.1 million during the same period in 2017, which represents an increase of $8.7 million or 24.8%, excluding corporate administration expenses.
Highlights of the changes are summarized in the following table:

(all dollar amounts in $ millions) | Three Months Ended September 30
Prior Period Operating Profit | $ | 35.1 |
Existing Facilities |
Hydro: Decrease is primarily due to lower production in all regions. The Maritime Region realized lower average market rates and higher operating expenses. | (1.4 | )
Wind Canada: Increase is due to higher production. | 0.2 |
Wind U.S.: Decrease is primarily due to lower HLBV income compared to the prior year partially offset by higher production across all U.S. Wind Facilities. | (3.1 | )
Solar U.S.: | 0.1 |
Thermal: Increase is primarily due to higher overall production partially offset by increased fuel costs. | 1.0 |
Other: | 0.3 |
| (2.9 | )
New Facilities |
Solar U.S.: Great Bay Solar achieved full COD in March 2018. | 2.1 |
Amherst Island Wind Facility: Interest and equity income received as it achieved COD in June 2018. | 1.5 |
Atlantica: Dividends received from the 25% equity interest in Atlantica acquired on March 9, 2018. | 8.4 |
| 12.0 |
Foreign Exchange | (0.4 | )
Current Period Divisional Operating Profit 1 | $ | 43.8 |

1 | See Non-GAAP Financial Measures.

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

2018 Year-To-Date Operating Results
For the nine months ended September 30, 2018, the Liberty Power Group's facilities generated $226.7 million of operating profit as compared to $137.1 million during the same period in 2017, which represents an increase of $89.6 million or 65.4%, excluding corporate administration expenses.
Highlights of the changes are summarized in the following table:

(all dollar amounts in $ millions) | Nine Months Ended September 30
Prior Period Operating Profit | $ | 137.1 |
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. | (3.4 | )
Wind U.S.: Increase is primarily due to HLBV income acceleration resulting from U.S. Tax Reform, partially offset by lower production. | 47.6 |
Solar Canada: Increase is due to higher production. | 0.2 |
Solar U.S.: Increase is primarily due to HLBV income acceleration resulting from U.S. Tax Reform. | 1.1 |
Thermal: Increase is primarily due to higher overall production as well as a new capacity-based contract at the Sanger Thermal Facility, partially offset by an increase in fuel costs. | 3.2 |
Other: | (0.5 | )
| 48.2 |
New Facilities |
Wind U.S.: Acquisition of Deerfield Wind Facility in March 2017. | 9.2 |
Solar U.S.: Great Bay Solar achieved full COD in March 2018. | 6.0 |
Amherst Island Wind Facility: Interest and equity income received as it achieved COD in June 2018. | 1.6 |
Atlantica: Dividends received from the 25% equity interest in Atlantica acquired on March 9, 2018. | 23.7 |
| 40.5 |
Foreign Exchange | 0.9 |
Current Period Divisional Operating Profit 1 | $ | 226.7 |

1 | See Non-GAAP Financial Measures.

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 in the first quarter of 2018 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.

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

LIBERTY UTILITIES GROUP
The Liberty Utilities Group operates rate-regulated utilities that provide distribution services to approximately 766,000 connections in the natural gas, electric, water and wastewater sectors. The Liberty Utilities Group's strategy is to grow its business organically and through business development activities while using prudent acquisition criteria. The Liberty Utilities Group believes that its business results are maximized by building constructive regulatory and customer relationships, and enhancing connections in the communities in which it operates.

Utility System Type | As at September 30
2018 | 2017
(all dollar amounts in $ millions) | Assets | Total Connections 1 | Assets | Total Connections 1
Electricity | $ | 2,548.2 |  | 265,000 |  | $ | 2,452.1 |  | 264,000 |
Natural Gas | 1,030.8 |  | 338,000 |  | 959.9 |  | 335,000 |
Water and Wastewater | 466.4 |  | 163,000 |  | 457.4 |  | 159,000 |
Total | $ | 4,045.4 |  | 766,000 |  | $ | 3,869.4 |  | 758,000 |
Accumulated Deferred Income Taxes Liability | $ | 419.8 |  |  | $ | 693.5 |  |

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

The Liberty Utilities Group aggregates the performance of its utility operations by utility system type – electricity, natural gas, and water and wastewater systems.
The electric distribution systems are comprised of regulated electrical distribution utility systems and serve approximately 265,000 connections in the states of California, New Hampshire, Missouri, Kansas, Oklahoma, and Arkansas.
The natural gas distribution systems are comprised of regulated natural gas distribution utility systems and serve approximately 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 163,000 connections located in the states of Arkansas, Arizona, California, Illinois, Missouri, and Texas.
2018 Usage Results

Electric Distribution Systems | Three Months Ended September 30 |  | Nine Months Ended September 30
| 2018 |  | 2017 |  | 2018 |  | 2017
Average Active Electric Connections For The Period |  |  |  |  |  |  |
Residential | 225,200 |  |  | 223,700 |  |  | 224,900 |  |  | 223,400 |
Commercial and industrial | 37,700 |  |  | 39,200 |  |  | 37,700 |  |  | 39,100 |
Total Average Active Electric Connections For The Period | 262,900 |  |  | 262,900 |  |  | 262,600 |  |  | 262,500 |
Customer Usage (GW-hrs) |  |  |  |  |  |  |
Residential | 649.2 |  |  | 616.5 |  |  | 1,923.9 |  |  | 1,748.4 |
Commercial and industrial | 1,084.0 |  |  | 953.7 |  |  | 3,017.7 |  |  | 2,640.8 |
Total Customer Usage (GW-hrs) | 1,733.2 |  |  | 1,570.2 |  |  | 4,941.6 |  |  | 4,389.2 |

For the three months ended September 30, 2018, the electric distribution systems' usage totaled 1,733.2 GW-hrs as compared to 1,570.2 GW-hrs for the same period in 2017, an increase of 163.0 GW-hrs or 10.4% primarily due to higher cooling degree days at the Empire Electric System.
For the nine months ended September 30, 2018, the electric distribution systems' usage totaled 4,941.6 GW-hrs as compared to 4,389.2 GW-hrs for the same period in 2017, an increase of 552.4 GW-hrs or 12.6%. The increase is primarily due to higher heating degree days in the first quarter and higher cooling degree days in the second and third quarters at the Empire Electric System.

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

Natural Gas Distribution Systems | Three Months Ended September 30 |  | Nine Months Ended September 30
| 2018 |  | 2017 |  | 2018 |  | 2017
Average Active Natural Gas Connections For The Period |  |  |  |  |  |  |
Residential | 285,000 |  |  | 283,000 |  |  | 288,600 |  |  | 287,100 |
Commercial and industrial | 31,000 |  |  | 30,900 |  |  | 31,600 |  |  | 31,600 |
Total Average Active Natural Gas Connections For The Period | 316,000 |  |  | 313,900 |  |  | 320,200 |  |  | 318,700 |
Customer Usage (MMBTU) |  |  |  |  |  |  |
Residential | 1,105,000 |  |  | 1,101,000 |  |  | 13,879,000 |  |  | 12,424,000 |
Commercial and industrial | 1,440,000 |  |  | 1,481,000 |  |  | 9,996,000 |  |  | 8,390,000 |
Total Customer Usage (MMBTU) | 2,545,000 |  |  | 2,582,000 |  |  | 23,875,000 |  |  | 20,814,000 |

For the three months ended September 30, 2018, usage at the natural gas distribution systems totaled 2,545,000 MMBTU as compared to 2,582,000 MMBTU during the same period in 2017, a decrease of 37,000 MMBTU, or 1.4%.
For the nine months ended September 30, 2018, usage at the natural gas distribution systems totaled 23,875,000 MMBTU as compared to 20,814,000 MMBTU during the same period in 2017, an increase of 3,061,000 MMBTU or 14.7%. 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 September 30 |  | Nine Months Ended September 30
| 2018 |  | 2017 |  | 2018 |  | 2017
Average Active Connections For The Period |  |  |  |  |  |  |
Wastewater connections | 42,200 |  |  | 41,000 |  |  | 42,000 |  |  | 40,900 |
Water distribution connections | 112,800 |  |  | 111,700 |  |  | 112,600 |  |  | 124,500 |
Total Average Active Connections For The Period | 155,000 |  |  | 152,700 |  |  | 154,600 |  |  | 165,400 |
Gallons Provided |  |  |  |  |  |  |
Wastewater treated (millions of gallons) | 558 |  |  | 547 |  |  | 1,676 |  |  | 1,670 |
Water provided (millions of gallons) | 5,141 |  |  | 4,895 |  |  | 12,168 |  |  | 12,996 |
Total Gallons Provided | 5,699 |  |  | 5,442 |  |  | 13,844 |  |  | 14,666 |

During the three months ended September 30, 2018, the water and wastewater distribution systems provided approximately 5,141 million gallons of water to its customers and treated approximately 558 million gallons of wastewater as compared to 4,895 million gallons of water provided and 547 million gallons of wastewater treated during the same period in 2017.
During the nine months ended September 30, 2018, the water and wastewater distribution systems provided approximately 12,168 million gallons of water to its customers and treated approximately 1,676 million gallons of wastewater as compared to 12,996 million gallons of water and 1,670 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.

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

2018 Liberty Utilities Group Operating Results |  |  |  |
| Three Months Ended September 30 |  | Nine Months Ended September 30
(all dollar amounts in $ millions) | 2018 |  | 2017 |  | 2018 |  | 2017
Revenue |  |  |  |  |  |  |
Utility electricity sales and distribution | $ | 225.5 |  |  | $ | 217.4 |  |  | $ | 638.0 |  |  | $ | 576.5 |
Less: cost of sales – electricity | (67.7 | ) |  | (65.2 | ) |  | (201.8 | ) |  | (170.8 | )
Net Utility Sales - electricity 1 | 157.8 |  |  | 152.2 |  |  | 436.2 |  |  | 405.7 |
Utility natural gas sales and distribution | 41.2 |  |  | 42.8 |  |  | 280.0 |  |  | 236.2 |
Less: cost of sales – natural gas | (9.9 | ) |  | (10.6 | ) |  | (124.0 | ) |  | (88.6 | )
Net Utility Sales - natural gas 1 | 31.3 |  |  | 32.2 |  |  | 156.0 |  |  | 147.6 |
Utility water distribution & wastewater treatment sales and distribution | 36.9 |  |  | 38.2 |  |  | 98.0 |  |  | 108.6 |
Less: cost of sales – water | (2.4 | ) |  | (2.7 | ) |  | (6.7 | ) |  | (7.1 | )
Net Utility Sales - water distribution & wastewater treatment 1 | 34.5 |  |  | 35.5 |  |  | 91.3 |  |  | 101.5 |
Gas transportation | 5.0 |  |  | 4.3 |  |  | 23.0 |  |  | 21.6 |
Other revenue | 2.8 |  |  | 3.0 |  |  | 6.8 |  |  | 6.7 |
Net Utility Sales 1 | 231.4 |  |  | 227.2 |  |  | 713.3 |  |  | 683.1 |
Operating expenses | (98.5 | ) |  | (94.0 | ) |  | (302.5 | ) |  | (291.0 | )
Other income | 1.3 |  |  | 0.9 |  |  | 4.1 |  |  | 2.8 |
HLBV income 2 | 0.6 |  |  | 1.6 |  |  | 2.6 |  |  | 4.8 |
Divisional Operating Profit 1,3 | $ | 134.8 |  |  | $ | 135.7 |  |  | $ | 417.5 |  |  | $ | 399.7 |

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 by 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 | 20

2018 Third Quarter Operating Results
For the three months ended September 30, 2018, the Liberty Utilities Group reported an operating profit (excluding corporate administration expenses) of $134.8 million as compared to $135.7 million for the comparable period in the prior year, a decrease of $0.9 million or 1%.
Highlights of the changes are summarized in the following table:

(all dollar amounts in $ millions) | Three Months Ended September 30
Prior Period Operating Profit | $ | 135.7 |
Existing Facilities |
Electricity: Increase is primarily due to warmer weather and higher cooling degree days which resulted in higher consumption at the Empire Electric System, offset by higher operating costs at the Granite State Electric System. | 2.5 |
Gas: Decrease is primarily due to lower consumption across the gas systems and higher operating costs at the EnergyNorth and Peach State Gas Systems. | (1.5 | )
Water: Increase is primarily due to operating cost savings across the Park Water System. | 0.3 |
Other: | 0.1 |
| 1.4 |
Rate Reviews |
Electricity: Implementation of lower rates at the Empire and Granite State Electric Systems due to U.S. Tax Reform. | (1.4 | )
Gas: Implementation of lower rates at the EnergyNorth and Peach State Gas Systems due to U.S. Tax Reform, partially offset by rate increases at the Midstates Gas System. | (0.3 | )
Water: Implementation of lower rates at the Arizona and Park Water Systems due to U.S. Tax Reform, partially offset by rate increases at the Litchfield Park Water System. | (0.6 | )
| (2.3 | )
Current Period Divisional Operating Profit 1 | $ | 134.8 |

1 | See Non-GAAP Financial Measures.

2018 Year-To-Date Operating Results
For the nine months ended September 30, 2018, the Liberty Utilities Group reported an operating profit (excluding corporate administration expenses) of $417.5 million as compared to $399.7 million for the comparable period in the prior year, an increase of $17.8 million or 4%, excluding corporate administration expenses.
Highlights of the changes are summarized in the following table:

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

(all dollar amounts in $ millions) | Nine Months Ended September 30
Prior Period Operating Profit | $ | 399.7 |
Existing Facilities |
Electricity: Increase is primarily due to higher heating degree days in the first quarter and higher cooling degree days in the second and third quarters of the year, which resulted in higher consumption at the Empire Electric System, partially offset by increase in operating costs. | 19.1 |
Gas: Increase is primarily due to higher heating degree days which resulted in higher consumption across the Midstates, EnergyNorth, and Empire Gas Systems, partially offset by an increase in operating costs at the Peach State Gas System. | 0.8 |
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 at most of the water systems. | (5.8 | )
Other: | 1.2 |
| 15.3 |
Rate Reviews |
Electricity: Implementation of new rates at the Granite State, Empire and Calpeco Electric Systems partially offset by lower rates due to U.S. Tax Reform. | 0.8 |
Gas: Implementation of new rates at the Midstates Gas System, partially offset by lower rates at the EnergyNorth and Peach State Gas Systems due to U.S. Tax Reform. | 2.3 |
Water: Implementation of lower rates at the Arizona and Park Water Systems due to U.S. Tax Reform, partially offset by rate increases at the Litchfield Park Water System. | (0.6 | )
| 2.5 |
Current Period Divisional Operating Profit 1 | $ | 417.5 |

1 | See Non-GAAP Financial Measures.

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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 |  |  |  |
Empire Electric System | Missouri | U.S. Tax Reform docket | $(17.8) | Prospective decrease in annual revenue of $17.8 million due to U.S. Tax Reform beginning August 30, 2018.
Various | Various | Various | $2.1 | Other rate reviews closed during and subsequent to the quarter with a combined approved rate increase of $1.6 million include: Missouri Water System ($1.0 million) and Litchfield Park Water & Sewer ($0.6 million).
Pending Rate Reviews |  |  |  |
Pine Bluff | Arkansas | Rate Case | $2.3 | In October 2018, filed an application requesting an increase of $2.3 million for water rates effective July 1, 2019.
Apple Valley Ranchos Water & Park Water Systems | California | GRC | $2.1 | On January 2, 2018, filed an application requesting an average rate increase of $0.7 million and $1.4 million, respectively and is to set rates for the three year period of 2019 to 2021.
Various | Various | Various | $2.9 | Other pending rate case requests include: Woodmark/Tall Timbers Wastewater Systems and Silverleaf Texas Water and Wastewater Systems.

CORPORATE DEVELOPMENT ACTIVITIES
In November 2017, the Company outlined its strategic approach to the identification, development and ownership of new energy and water infrastructure investments. One element of this strategy is the aggregation of the Company’s energy and water infrastructure development activities under a newly formed development joint venture, AAGES. The AAGES joint venture combines the international infrastructure construction presence of Abengoa with the development expertise of APUC. Staffed with experienced APUC and Abengoa development professionals, AAGES has created a development team with a proven track record of successful North American and international project development.
Complementing the formation of AAGES, APUC has acquired a 25% interest in Atlantica and has agreed to acquire an additional 16.5% interest in Atlantica from Abengoa, bringing APUC’s investment in Atlantica to approximately 41.5%. This investment provides the Company with immediate accretion from an investment in a portfolio of high quality international clean energy and water infrastructure assets under long term contracts with high quality counterparties. More strategically, Atlantica represents a potential location into which AAGES’ international development projects may be held after commercial operations are achieved.
AAGES works with a global reach to identify, develop, and construct new renewable power generating facilities and water infrastructure assets. Under APUC’s strategy, AAGES’ responsibilities will include the provision of development oversight of APUC’s existing pipeline of North American renewable energy development projects. AAGES currently has a staff of 20 people focused on international projects, based jointly in Seville, Spain and Oakville, Canada. Once a project developed by AAGES has reached commercial operation, 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.
The development and construction of new energy and water infrastructure projects involves a number of risks and uncertainties including scheduling delays, cost over runs and other events that may be beyond the control of the Company (See Operational Risk Management - Development and Construction Risk).
The projects listed below 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 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.

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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.
A contract for the development of the site was signed in the first quarter of 2018. Site grading work is now complete and foundation work is underway. All equipment has been delivered to site and installation is ongoing.
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 12, 2018, an order was received from the MPSC supporting various requests related to the proposed investment plan.
The proposed new wind generating capacity is forecast to generate approximately 2,400 GW-hrs of energy per year which will be consumed 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.
Agreements have been executed with a credit-worthy counterparty for the design and construction of the first 300 MW of wind generation projects (the North Fork Ridge and Kings Point Wind Projects) and negotiations for the remaining 300 MW project are nearing completion. As part of the normal course regulatory process, specific site approval dockets for the first two projects are under review by the MPSC. The estimated construction cycle for the projects is 12 to 18 months.
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 is comprised of a 27 mile lateral natural gas pipeline, connecting the Portland Natural Gas Transmission System and the Maritimes & Northeast Pipeline (Joint Facilities) to the Liberty Utilities Groups' New Hampshire distribution system. The pipeline will be constructed in a designated energy infrastructure corridor along Route 101 in New Hampshire. In addition, the project includes a 2 bcf double walled storage tank and liquefaction and vaporization equipment, all of which will be located in an abandoned quarry to minimize social sightlines impact.
The Liberty Utilities Group filed for approval of its plan to construct the project with the NHPUC on December 22, 2017, and a decision is expected in mid-2019.
The Liberty Utilities Group has commenced environmental, geotechnical and survey work on the project, and has received preliminary acceptance from the New Hampshire Department of Transportation on its proposed pipeline route. Concurrently, public presentations have been made to all municipal boards in the host communities. Communication to key stakeholders including first responders, elected officials, environmental organizations, businesses groups, labor, and employees is ongoing. 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.
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 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 both the rural municipalities of Lawtonia and Morse.
SaskPower has commenced engineering design for the required interconnection facilities.

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Based on the recently completed system impact study for the project, the expected time frame for design and construction is 24 to 36 months. 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).
Development of the project is planned to be completed in two phases. The first phase ("Phase I") representing installed generating capacity of 24 MW is expected to qualify as Canadian Renewable Conservation Expense and, therefore, is expected to be eligible for a refundable tax credit equal to approximately 28% of eligible Phase I construction costs.
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. Phase I construction is to begin in the second quarter of 2019, with commissioning to occur in the fourth quarter of 2019.
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. The interconnection agreement is expected to be executed later this year. Work is on-going 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 early 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 in 2020. The balance of the 122 MW of proposed capacity will be completed in 2021/2022. 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. Energy from Phase I of the project is expected to be sold pursuant to a long term financial hedge.
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 northern Illinois. The facility 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 facility is from the end of 2020 to early 2021.
Sandy Ridge II Wind Project
The Sandy Ridge II Wind Project is a 100 MW expansion of the Liberty Power Group’s operational Sandy Ridge Wind Facility, located in Blair County, Pennsylvania. The facility 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 facility is from the end of 2020 to early 2021.
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 the following projects:
ATN3 Electric Transmission Project
The ATN3 electric transmission project is a 205 mile, 220 KV electric transmission development project located in southeast Peru. The project will receive U.S. dollar indexed revenues under a 30 year concession agreement with the Peruvian Ministry of Energy and Mines (Moody’s Rating of A3), guaranteed by the Peruvian government. Ownership of the project will be transferred to the government of Peru at the end of the 30 year concession term.

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The development of the project was commenced by Abengoa in June 2013. Through 2015 the required Environmental Impact Study was approved, the majority of necessary land rights-of-way secured and engineering and procurement completed. Progress was halted in 2016 as a result of Abengoa’s financial difficulties, triggering a default under the project debt covenants.
AAGES continues to evaluate the attractiveness of the project and has reached an agreement with the project lenders to complete development of the project, subject to certain conditions precedent including: amendment of the Concession Agreement to reflect the updated schedule, securing of additional land for a new substation, finalization of a satisfactory EPC contract and obtaining the project financing for construction.
A final investment decision is expected to be made during the fourth quarter of 2018. An agreement has also been reached for the participation of Atlantica in the project during the development process and the transfer to Atlantica following COD.
APUC: CORPORATE AND OTHER EXPENSES

| Three Months Ended September 30 |  | Nine Months Ended September 30
(all dollar amounts in $ millions) | 2018 |  | 2017 |  | 2018 |  | 2017
Corporate and other expenses: |  |  |  |  |  |  |
Administrative expenses | $ | 11.5 |  |  | $ | 11.5 |  |  | $ | 37.7 |  |  | $ | 34.9 |
Loss (gain) on foreign exchange | 0.3 |  |  | 2.1 |  |  | (0.8 | ) |  | (0.9 | )
Interest expense on convertible debentures and costs related to acquisition financing | — |  |  | — |  |  | — |  |  | 13.4 |
Interest expense | 37.9 |  |  | 36.4 |  |  | 111.8 |  |  | 109.1 |
Depreciation and amortization | 63.5 |  |  | 56.9 |  |  | 196.9 |  |  | 182.1 |
Change in value of investment carried at fair value | (10.1 | ) |  | — |  |  | 91.9 |  |  | — |
Interest, dividend, equity, and other loss (income)1 | 1.5 |  |  | (0.5 | ) |  | 0.4 |  |  | (1.7 | )
Pension and post-employment non-service costs 2 | 1.5 |  |  | 1.7 |  |  | 2.5 |  |  | 6.5 |
Other losses (gains) | 2.0 |  |  | 0.7 |  |  | 0.4 |  |  | (3.0 | )
Acquisition-related costs | 1.0 |  |  | 0.8 |  |  | 9.6 |  |  | 46.7 |
Loss on derivative financial instruments | 0.7 |  |  | — |  |  | 0.9 |  |  | 1.2 |
Income tax expense | 10.6 |  |  | 11.7 |  |  | 50.6 |  |  | 43.7 |

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 8 in the unaudited interim financial statements for further details.

2018 Third Quarter Corporate and Other Expenses
During the three months ended September 30, 2018, administrative expenses totaled $11.5 million as compared to $11.5 million in the same period in 2017.
For the three months ended September 30, 2018, interest expense totaled $37.9 million as compared to $36.4 million in the same period in 2017. The increase is primarily due to drawings under the Corporate Term Facility to finance the Atlantica acquisition, partially offset by debt maturities.
For the three months ended September 30, 2018, depreciation expense totaled $63.5 million as compared to $56.9 million in the same period in 2017. The increase is primarily due to an increase in property, plant and equipment as well as a one-time adjustment due to regulatory proceedings.
For the three months ended September 30, 2018, change in investment carried at fair value totaled $10.1 million as compared to $nil in 2017. The 2018 change in fair value reflects an unrealized gain related to the investment in Atlantica (see Note 6 in the unaudited interim financial statements).
For the three months ended September 30, 2018, pension and post-employment non-service costs totaled $1.5 million as compared to $1.7 million in 2017. The $0.2 million decrease primarily relates to a higher expected return on plan assets in 2018.
For the three months ended September 30, 2018, other losses were $2.0 million as compared to $0.7 million in the same period in 2017. The loss in 2018 is primarily related to settlement costs incurred on the acquisition of the Deerfield Wind Facility, as well as a write-off of rate review expenses. The loss in 2017 is primarily related to the write-off of rate review expenses for several water utilities.

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

For the three months ended September 30, 2018, acquisition-related costs totaled $1.0 million as compared to $0.8 million in 2017.
For the three months ended September 30, 2018, the loss on derivative financial instruments totaled $0.7 million as compared to a loss of $nil in the same period in 2017. 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.
For the three months ended September 30, 2018, an income tax expense of $10.6 million was recorded as compared to an income tax expense of $11.7 million during the same period in 2017. The lower income tax expense in 2018 is primarily due to lower tax rates as a result of U.S. Tax Reform.
2018 Year-To-Date Corporate and Other Expenses
During the nine months ended September 30, 2018, administrative expenses totaled $37.7 million as compared to $34.9 million in the same period in 2017. The increase is primarily due to additional costs incurred to administer APUC's operations as a result of the Company's growth.
For the nine months ended September 30, 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 nine months ended September 30, 2018, depreciation expense totaled $196.9 million as compared to $182.1 million in the same period in 2017. The increase is primarily due to an increase in property, plant and equipment as well as a one-time adjustment due to regulatory proceedings.
For the nine months ended September 30, 2018, interest expense totaled $111.8 million as compared to $109.1 million in the same period in 2017. The increase is primarily due to drawings under the Corporate Term Facility to finance the Atlantica acquisition, partially offset by debt maturities.
For the nine months ended September 30, 2018, change in investment carried at fair value totaled $91.9 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 6 in the unaudited interim financial statements).
For the nine months ended September 30, 2018 pension and post-employment non-service costs totaled $2.5 million as compared to $6.5 million in 2017. The $4.0 million decrease primarily relates to a higher expected return on plan assets in 2018.
For the nine months ended September 30, 2018, other losses (gains) were in a loss position of $0.4 million as compared to a gain of $3.0 million in the same period in 2017. The loss in 2018 is primarily related to settlement costs incurred on the acquisition of the Deerfield Wind Facility, as well as a write-off of rate review expenses, partially offset by a gain on the sale of the Company's interest in the Northeast Energy Center LLC Joint Venture. The prior period gain is primarily related to the disposition of the Mountain Water utility, partially offset by the write-off of rate review expenses for several water utilities.
For the nine months ended September 30, 2018, acquisition-related costs totaled $9.6 million as compared to $46.7 million in the same period in 2017. The costs in 2018 primarily related to the investment in Atlantica, and the costs in 2017 primarily related to the acquisition of Empire.
For the nine months ended September 30, 2018, the loss on derivative financial instruments totaled $0.9 million as compared to a loss of $1.2 million in the same period in 2017.
An income tax expense of $50.6 million was recorded in the nine months ended September 30, 2018 as compared to an income tax expense of $43.7 million during the same period in 2017. The increase in income tax expense is primarily due to higher operational earnings, including HLBV, offset by lower tax rates as a result of U.S. Tax Reform. The company did not record a tax benefit on the immediate fair value loss recorded on its investment in Atlantica.
At December 31, 2017, the Company recorded provisional amounts related to U.S. Tax Reform as allowed under SEC Staff Accounting Bulletin 118 ("SAB 118"). In addition, SAB 118 allowed for a measurement period for companies to finalize the provisional amounts recorded as of December 31, 2017, not to exceed one year. As of September 30, 2018, the Company has not yet finalized its assessment of the provisional amounts and there were no significant adjustments recorded in the first nine months of 2018. The Company expects to complete its assessment and record any final adjustments to the provisional amounts by the fourth quarter of 2018.

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 September 30 |  | Nine Months Ended September 30
(all dollar amounts in $ millions) | 2018 |  | 2017 |  | 2018 |  | 2017
Net earnings attributable to shareholders | $ | 57.9 |  |  | $ | 47.7 |  |  | $ | 141.0 |  |  | $ | 102.3 |
Add (deduct): |  |  |  |  |  |  |
Net earnings attributable to the non-controlling interest, exclusive of HLBV | 0.3 |  |  | 0.5 |  |  | 1.4 |  |  | 1.8 |
Income tax expense | 10.7 |  |  | 11.7 |  |  | 50.6 |  |  | 43.7 |
Interest expense on convertible debentures and costs related to acquisition financing | — |  |  | — |  |  | — |  |  | 13.4 |
Interest expense on long-term debt and others | 37.9 |  |  | 36.4 |  |  | 111.8 |  |  | 109.1 |
Other losses (gains) | 2.0 |  |  | 0.6 |  |  | 0.4 |  |  | (3.1 | )
Acquisition-related costs | 1.0 |  |  | 0.8 |  |  | 9.6 |  |  | 46.7 |
Change in value of investment in Atlantica carried at fair value | (10.1 | ) |  | — |  |  | 91.9 |  |  | — |
Costs related to tax equity financing | — |  |  | 1.0 |  |  | — |  |  | 1.4 |
Loss on derivative financial instruments | 0.7 |  |  | — |  |  | 0.9 |  |  | 1.2 |
Realized loss on energy derivative contracts | — |  |  | — |  |  | — |  |  | (0.6 | )
Loss (gain) on foreign exchange | 0.3 |  |  | 2.1 |  |  | (0.8 | ) |  | (0.9 | )
Depreciation and amortization | 63.5 |  |  | 56.9 |  |  | 196.9 |  |  | 182.1 |
Adjusted EBITDA | $ | 164.2 |  |  | $ | 157.7 |  |  | $ | 603.7 |  |  | $ | 497.1 |

HLBV represents the value of net tax attributes earned during the period primarily from electricity generated by certain U.S. wind power and U.S. solar generation facilities. HLBV earned in the three and nine months ended September 30, 2018 amounted to $5.5 million and $96.8 million as compared to $10.4 million and $40.8 million during the same period in 2017.

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 September 30 |  | Nine Months Ended September 30
(all dollar amounts in $ millions) | 2018 |  | 2017 |  | 2018 |  | 2017
Net earnings attributable to shareholders | $ | 57.9 |  |  | $ | 47.7 |  |  | $ | 141.0 |  |  | $ | 102.3 |
Add (deduct): |  |  |  |  |  |  |
Loss on derivative financial instruments | 0.7 |  |  | — |  |  | 0.9 |  |  | 1.2 |
Realized loss on energy derivative contracts | — |  |  | — |  |  | — |  |  | (0.6 | )
Other losses (gains) | 0.3 |  |  | 0.6 |  |  | (1.1 | ) |  | (3.0 | )
Loss (gain) on foreign exchange | 0.3 |  |  | 2.1 |  |  | (0.8 | ) |  | (0.9 | )
Interest expense on convertible debentures and costs related to acquisition financing | — |  |  | — |  |  | — |  |  | 13.4 |
Acquisition-related costs | 1.0 |  |  | 0.8 |  |  | 9.6 |  |  | 46.7 |
Change in value of investment in Atlantica carried at fair value | (10.1 | ) |  | — |  |  | 91.9 |  |  | — |
Costs related to tax equity financing | — |  |  | 1.0 |  |  | — |  |  | 1.4 |
Adjustment for taxes related to above | (0.4 | ) |  | (0.2 | ) |  | 0.1 |  |  | (2.5 | )
Adjusted Net Earnings | $ | 49.7 |  |  | $ | 52.0 |  |  | $ | 241.6 |  |  | $ | 158.0 |
Adjusted Net Earnings per share 1 | $ | 0.10 |  |  | $ | 0.13 |  |  | $ | 0.52 |  |  | $ | 0.41 |

1 | Per share amount calculated after preferred share dividends.

For the three months ended September 30, 2018, Adjusted Net Earnings totaled $49.7 million as compared to Adjusted Net Earnings of $52.0 million for the same period in 2017, a decrease of $2.3 million.
For the nine months ended September 30, 2018, Adjusted Net Earnings totaled $241.6 million as compared to Adjusted Net Earnings of $158.0 million for the same period in 2017, an increase of $83.6 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 September 30 |  | Nine Months Ended September 30
(all dollar amounts in $ millions) | 2018 |  | 2017 |  | 2018 |  | 2017
Cash flows from operating activities | $ | 131.5 |  |  | $ | 98.4 |  |  | $ | 361.7 |  |  | $ | 210.6 |
Add (deduct): |  |  |  |  |  |  |
Changes in non-cash operating items | (4.8 | ) |  | 5.1 |  |  | 35.4 |  |  | 78.7 |
Production based cash contributions from non-controlling interests | — |  |  | — |  |  | 13.9 |  |  | 7.9 |
Interest expense on convertible debentures and costs related to acquisition financing 1 | — |  |  | — |  |  | — |  |  | 7.2 |
Acquisition-related costs | 1.0 |  |  | 0.8 |  |  | 9.6 |  |  | 46.7 |
Reimbursement of operating expenses incurred on joint venture | — |  |  | — |  |  | 1.0 |  |  | — |
Adjusted Funds from Operations | $ | 127.7 |  |  | $ | 104.3 |  |  | $ | 421.6 |  |  | $ | 351.1 |

1 | Exclusive of deferred financing fees of $6.2 million in 2017.

For the three months ended September 30, 2018, Adjusted Funds from Operations totaled $127.7 million as compared to Adjusted Funds from Operations of $104.3 million for the same period in 2017, an increase of $23.4 million. The increase in Adjusted Funds from Operations is primarily due to the timing of pension contributions as well as a one-time contribution of approximately $9.0 million to the pension plan in 2017 to reduce the Company's defined benefit pension obligations.
SUMMARY OF PROPERTY, PLANT, AND EQUIPMENT EXPENDITURES 1

| Three Months Ended September 30 |  | Nine Months Ended September 30
(all dollar amounts in $ millions) | 2018 |  | 2017 |  | 2018 |  | 2017
Liberty Power Group: |  |  |  |  |  |  |
Maintenance | $ | 6.7 |  |  | $ | 3.0 |  |  | $ | 14.8 |  |  | $ | 10.7 |
Investment in Capital Projects 1 | 29.5 |  |  | 87.5 |  |  | 89.6 |  |  | 456.5 |
| $ | 36.2 |  |  | $ | 90.5 |  |  | $ | 104.4 |  |  | $ | 467.2 |
Liberty Utilities Group: |  |  |  |  |  |  |
Rate Base Maintenance | $ | 46.7 |  |  | $ | 40.6 |  |  | $ | 136.2 |  |  | $ | 125.0 |
Rate Base Acquisition | — |  |  | — |  |  | — |  |  | 2,058.2 |
Rate Base Growth | 50.0 |  |  | 55.0 |  |  | 97.9 |  |  | 202.1 |
| 96.7 |  |  | 95.6 |  |  | 234.1 |  |  | 2,385.3 |
International Investments 2 | $ | — |  |  | $ | — |  |  | $ | 612.6 |  |  | $ | — |
Total Capital Expenditures | $ | 132.9 |  |  | $ | 186.1 |  |  | $ | 951.1 |  |  | $ | 2,852.5 |

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.

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

2018 Third Quarter Property Plant and Equipment Expenditures
During the three months ended September 30, 2018, the Liberty Power Group incurred capital expenditures of $36.2 million as compared to $90.5 million during the same period in 2017. The capital expenditures include the post COD construction costs of the Great Bay Solar and Amherst Wind facilities. They also include costs related to environmental permitting for the Blue Hill project, the finalization of material construction contracts on the Val Eo project and ongoing maintenance capital at existing operating sites.
During the three months ended September 30, 2018, the Liberty Utilities Group invested $96.7 million in capital expenditures as compared to $95.6 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, 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.
2018 Year-To-Date Property Plant and Equipment Expenditures
During the nine months ended September 30, 2018, the Liberty Power Group incurred capital expenditures of $104.4 million as compared to $467.2 million during the same period in 2017. The capital expenditures include completing the construction of the Great Bay Solar, and Amherst Wind Facilities, early stages of environmental permitting for the Blue Hill project, the finalization of material construction contracts on the Val Eo project, and ongoing maintenance capital at existing operating sites.
During the nine months ended September 30, 2018, the Liberty Utilities Group incurred capital expenditures of $234.1 million as compared to $2.4 billion during the same period in 2017. Excluding the acquisition of Empire, the Liberty Utilities Group incurred capital expenditures of $327.1 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, 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 nine months ended September 30, 2018, the Company completed both its initial 25% equity investment in Atlantica and also its investment into the AAGES joint ventures for approximately $607.6 million and $5.0 million, respectively.
2018 Capital Investments
In 2018, the Company plans to spend between $1.4 billion and $1.5 billion on capital investment opportunities. Actual expenditures during the course of 2018 may vary due to timing of various project investments and the realized Canadian to U.S. dollar exchange rate.
Expected 2018 capital investment ranges are as follows:

(all dollar amounts in $ millions) |  |  |
Liberty Power Group: |  |  |
Maintenance | $ | 10.0 |  | - | $ | 30.0 |
Investment in Capital Projects | 120.0 |  | - | 140.0 |
Total Liberty Power Group: | $ | 130.0 |  | - | $ | 170.0 |
Liberty Utilities Group: |  |  |
Rate Base Maintenance | $ | 170.0 |  | - | $ | 190.0 |
Rate Base Growth | 130.0 |  | - | 150.0 |
Total Liberty Utilities Group: | $ | 300.0 |  | - | $ | 340.0 |
International Investments 1 | $ | 950.0 |  |  | $ | 1,000.0 |
Total 2018 Capital Investments | $ | 1,380.0 |  | - | $ | 1,510.0 |

1 |  | See Major Highlights.

The Liberty Power Group intends to spend between $130.0 million - $170.0 million over the course of 2018 to develop or further invest in capital projects. Additionally, the Liberty Power Group plans to spend between $10.0 million - $30.0 million on various operational solar, thermal, and wind assets to maintain safety, regulatory, and operational efficiencies.

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

The remaining material fourth quarter projects primarily relate to early stages of environmental permitting for the Blue Hill Wind Project, the finalization of material construction contracts on the Val-Éo Wind Project, and the final development of the Amherst Island Wind Project.
The Liberty Utilities Group intends to spend between $300.0 million - $340.0 million over the course of 2018 in an effort to improve the reliability of the utility systems and broaden the technologies used to better serve its service areas. The remaining material fourth quarter projects entail spending capital for structural improvements, specifically in relation to completing main replacements, well construction, expanding electrical grids to service new customers, and installing new and refreshing existing substations.
LIQUIDITY AND CAPITAL RESERVES
APUC has revolving credit and letter of credit facilities available for Corporate, the Liberty Power Group, and the Liberty Utilities Group to manage the liquidity and working capital requirements of each division (collectively the “Bank Credit Facilities”).
Bank Credit Facilities
The following table sets out the Bank Credit Facilities available to APUC and its operating groups as at September 30, 2018:

| As at September 30, 2018 |  | As at Dec 31, 2017
(all dollar amounts in $ millions) | Corporate |  | Liberty Power |  | Liberty Utilities |  | Total |  | Total
Credit facilities | $ | 127.5 |  |  | $ | 700.0 |  | 1 | $ | 500.0 |  |  | $ | 1,327.5 |  |  | $ | 1,101.4 |
Funds drawn on facilities | — |  |  | (178.5 | ) |  | (122.5 | ) |  | (301.0 | ) |  | (48.7 | )
Letters of credit issued | (13.1 | ) |  | (118.1 | ) |  | (7.8 | ) |  | (139.0 | ) |  | (139.3 | )
Liquidity available under the facilities | 114.4 |  |  | 403.4 |  |  | 369.7 |  |  | 887.5 |  |  | 913.4 |
Cash on hand |  |  |  |  |  |  | 88.2 |  |  | 43.5 |
Total Liquidity and Capital Reserves | $ | 114.4 |  |  | $ | 403.4 |  |  | $ | 369.7 |  |  | $ | 975.7 |  |  | $ | 956.9 |
1 Includes a $200 million uncommitted stand alone letter of credit facility.

As at September 30, 2018, the Company's C$165.0 million senior unsecured revolving credit facility (the "Corporate Credit Facility") was undrawn and had $13.1 million of outstanding letters of credit. The facility matures on November 19, 2018 and is subject to customary covenants. The Company plans to extend the facility for one year.
On December 21, 2017, the Company entered into a $600.0 million term credit facility with two Canadian banks maturing on December 21, 2018. The proceeds of the term credit facility provide the Company with additional liquidity for general corporate purposes and acquisitions. On March 7, 2018 the Company drew $600.0 million and during the second and fourth quarter the Company repaid $132.5 million and $280.7 million on the facility. As at November 8, 2018 the balance outstanding on the facility is $186.8 million and is expected to be repaid prior to maturity.
As at September 30, 2018, the Liberty Power Group's committed bank lines consisted of a $500.0 million senior unsecured syndicated revolving credit facility (the "Liberty Power Credit Facility") and a $200.0 million letter of credit facility. As at September 30, 2018, the credit facility had drawn $178.5 million and had $118.1 million in outstanding letters of credit. On August 1, 2018 the Liberty Power Credit Facility maturity date was extended by one year to October 6, 2023.
As at September 30, 2018, the Liberty Utilities Group's $500.0 million senior unsecured syndicated revolving credit facility (the "Liberty Credit Facility") had drawn $122.5 million and had $7.8 million of outstanding letters of credit. The facility matures on February 23, 2023 and is subject to customary covenants.
Long Term Debt
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. APUC's application to list the subordinated notes on the NYSE has been approved and they are now trading under the ticker symbol "AQNA".

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

The notes mature in 60 years 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 have been assigned a rating of BB+/BB+ from S&P and Fitch. The notes are 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.
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.
Convertible Unsecured Subordinated Debentures
In the first quarter of 2016, in connection with the acquisition of Empire, APUC and its direct wholly-owned subsidiary, Liberty Utilities (Canada) Corp., entered into an agreement with a syndicate of underwriters under which the underwriters agreed to buy, on a bought deal basis, C$1.15 billion aggregate principal amount of 5.00% convertible unsecured subordinated debentures ("Debentures") of APUC.
All Debentures were sold on an instalment basis at a price of C$1,000 dollars per debenture, of which C$333 dollars was paid on the closing of the Offering and the remaining C$667 dollars was payable on a date set by APUC upon satisfaction of all conditions precedent to the closing of the acquisition of Empire (the "Final Instalment Date"), at which time each debenture was convertible to 94.3396 common shares of APUC and bears an interest rate of 0% thereafter.
The Final Instalment Date was established as February 2, 2017, at which time APUC received the final instalment payment. The proceeds were used to repay a portion of the Acquisition Facility. As at November 7, approximately 99.9% of the Debentures have been converted into common shares of APUC, with APUC issuing approximately 108,424,744 common shares as a result of the conversion.
Credit Ratings
APUC has a long term consolidated corporate credit rating of BBB (flat) from Standard & Poor's ("S&P"), a BBB (low) rating from DBRS Limited ("DBRS") and a BBB (flat) issuer rating from Fitch.
APCo, the parent company for the Liberty Power Group, has a BBB (flat) issuer rating from S&P, a BBB (low) issuer rating from DBRS and a BBB (flat) issuer rating from Fitch.
Liberty Utilities Co., parent company for the Liberty Utilities Group, has a corporate credit rating of BBB (flat) from Standard & Poor's ("S&P"), a BBB (high) rating from DBRS Limited ("DBRS") and a BBB (flat) issuer rating from Fitch. Debt issued by Liberty Utilities Finance GP1 ("Liberty Finance"), a special purpose financing entity of Liberty Utilities Co., has a rating of BBB (high) from DBRS and BBB (high) from Fitch. Empire has an issuer rating of BBB (flat) rating from S&P and a Baa1 rating from Moody's Investors Service, Inc. ("Moody's").

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

Contractual Obligations
Information concerning contractual obligations as of September 30, 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 obligations 1 | $ | 3,535.9 |  |  | $ | 609.5 |  |  | $ | 427.0 |  |  | $ | 566.6 |  |  | $ | 1,932.8 |
Convertible debentures | 0.5 |  |  | — |  |  | — |  |  | — |  |  | 0.5 |
Advances in aid of construction | 64.4 |  |  | 1.1 |  |  | — |  |  | — |  |  | 63.3 |
Interest on long-term debt obligations | 1,570.5 |  |  | 148.0 |  |  | 255.8 |  |  | 207.5 |  |  | 959.2 |
Purchase obligations | 249.4 |  |  | 249.4 |  |  | — |  |  | — |  |  | — |
Environmental obligations | 58.8 |  |  | 1.4 |  |  | 30.3 |  |  | 4.1 |  |  | 23.0 |
Derivative financial instruments: |  |  |  |  |  |  |  |  |
Cross currency swap | 63.8 |  |  | 4.1 |  |  | 37.6 |  |  | 25.4 |  |  | (3.3 | )
Interest rate swap | 5.3 |  |  | 5.3 |  |  | — |  |  | — |  |  | — |
Energy derivative and commodity contracts | 1.7 |  |  | 0.9 |  |  | 0.8 |  |  | — |  |  | — |
Power Purchase Agreements | 284.0 |  |  | 45.2 |  |  | 21.9 |  |  | 22.8 |  |  | 194.1 |
Gas Supply and Service Agreements | 213.3 |  |  | 69.8 |  |  | 72.2 |  |  | 35.3 |  |  | 36.0 |
Service agreements | 507.6 |  |  | 38.4 |  |  | 79.1 |  |  | 72.7 |  |  | 317.4 |
Capital projects | 59.3 |  |  | 49.4 |  |  | 2.2 |  |  | 7.7 |  |  | — |
Operating leases | 217.3 |  |  | 7.9 |  |  | 14.4 |  |  | 13.9 |  |  | 181.1 |
Other obligations | 115.7 |  |  | 32.8 |  |  | — |  |  | — |  |  | 82.9 |
Total Obligations | $ | 6,947.5 |  |  | $ | 1,263.2 |  |  | $ | 941.3 |  |  | $ | 956.0 |  |  | $ | 3,787.0 |

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

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

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 September 30, 2018, APUC had 473,900,515 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$445 million. The proceeds of the offering were used to pay down existing indebtedness, and upon closing of the acquisition will be used, in part, to finance the purchase of an additional approximately 16.5% interest in Atlantica.
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 September 30, 2018, APUC had outstanding:

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

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

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

APUC has a shareholder dividend reinvestment plan (the “Reinvestment Plan”) for registered holders of common shares of APUC. As at September 30, 2018, 126,012,459 common shares representing approximately 27% of total common shares outstanding had been registered with the Reinvestment Plan. During the quarter ended September 30, 2018, 1,630,777 common shares were issued under the Reinvestment Plan, and subsequent to quarter-end, on October 12, 2018, an additional 1,719,089 common shares were issued under the Reinvestment Plan.
SHARE-BASED COMPENSATION PLANS
For the nine months ended September 30, 2018, APUC recorded $6.0 million in total share-based compensation expense as compared to $6.1 million for the same period in 2017. 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 September 30, 2018, total unrecognized compensation costs related to non-vested options and share unit awards were $1.8 million and $8.5 million, respectively, and are expected to be recognized over a period of 1.66 and 1.81 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 nine months ended September 30, 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. In March 2018, an executive of the Company exercised 512,367 stock options at a weighted average exercise price of $10.29 in exchange for 86,354 common shares issued from treasury and 426,013 options were settled at their cash value as payment for the exercise price and tax withholdings related to the exercise of the options.
As at September 30, 2018, a total of 7,393,208 options are issued and outstanding under the stock option plan.

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

Performance Share Units
APUC issues performance share units (“PSUs”) to certain members of management as part of APUC’s long-term incentive program. During the nine months ended September 30, 2018, the Company granted (including dividends and performance adjustments) 759,106 PSUs to executives and employees of the Company. During the nine months ended September 30, 2018, the Company settled 256,977 PSUs, of which 133,569 PSUs were exchanged for common shares issued from treasury and 123,408 PSUs were settled at their cash value as payment for tax withholdings related to the settlement of the PSUs. Additionally, during the nine months ended September 30, 2018, a total of 44,294 PSUs were forfeited.
As at September 30, 2018, a total of 1,406,782 PSUs are granted and outstanding under the PSU plan.
Directors Deferred Share Units
APUC has a Directors' Deferred Share Unit Plan. Under the plan, non-employee directors of APUC receive 50% of their annual compensation in deferred share units (“DSUs”) and may elect to receive any portion of their remaining compensation in DSUs. The DSUs provide for settlement in cash or shares at the election of APUC. As APUC does not expect to settle the DSUs in cash, these DSUs are accounted for as equity awards. During the nine months ended September 30, 2018, the Company issued 65,105 DSUs (including DSUs in lieu of dividends) to the directors of the Company.
As at September 30, 2018, a total of 359,012 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 nine months ended September 30, 2018, 129,980 RSUs were issued (including RSUs in lieu of dividends) to employees of the Company. During the quarter, the Company settled 4,544 RSUs in exchange for 2,111 common shares issued from treasury, and 2,433 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 nine months ended September 30, 2018, the Company issued 190,872 common shares to employees under the ESPP.
As at September 30, 2018, a total of 970,425 shares had been issued under the ESPP.
RELATED PARTY TRANSACTIONS
Equity-method investments
The Company provides administrative and development services to its equity-method investees and is reimbursed for incurred costs. To that effect, for the three and nine months ended September 30, 2018, the Company charged its equity-method investees $5.0 million and $6.9 million in 2018 as compared to $1.1 million and $3.1 million during the same period in 2017.
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.
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.

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ENTERPRISE RISK MANAGEMENT
An enterprise risk management ("ERM") framework is embedded across the organization that systematically and broadly identifies, assesses, and mitigates the key strategic, operational, financial, and compliance risks that may impact the achievement of APUC's objectives. 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 also set out in the most recent AIF and the annual MD&A.
Treasury Risk Management
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 September 30, 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 September 30, 2018. As a result, a 100 basis point change in the variable rate charged would not have an impact on interest expense;

• | The Liberty Power Group's revolving credit facility is subject to a variable interest rate and had $178.5 million outstanding as at September 30, 2018. As a result a 100 basis point change in the variable rate charged would impact interest expense by $1.8 million annually;

• | The Liberty Utilities Group's revolving credit facility is subject to a variable interest rate and had $122.5 million outstanding as at September 30, 2018. As a result, a 100 basis point change in the variable rate charged would impact interest expense by $1.2 million annually;

• | The Liberty Utilities Group's commercial paper program is subject to a variable interest rate and had no amounts outstanding at September 30, 2018. As a result, a 100 basis point change in the variable rate charged would not have an impact on interest expense; and

• | The corporate term facilities are subject to a variable interest rate and had $602.5 million outstanding as at September 30, 2018. A 100 basis point change in the variable rate charged would impact interest expense by $6.0 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 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.
Market Price Risk
The Liberty Power Group predominantly enters into long term PPAs for its generation assets and hence is not exposed to market risk for this portion of its portfolio. Where a generating asset is not covered by a power purchase contract, the Liberty Power Group may seek to mitigate market risk exposure by entering into financial or physical power hedges requiring that a specified amount of power be delivered at a specified time in return for a fixed price. There is a risk that the Company is not able to generate the specified amount of power at the specified time resulting in production shortfalls under the hedge that then requires the Company to purchase power in the merchant market. To mitigate the risk of production shortfalls under hedges, the Liberty Power Group generally seeks to structure hedges to cover less than 100% of the anticipated production, thereby reducing the risk of not producing the minimum hedge quantities. Nevertheless, due to unpredictability in the natural resource or due to grid curtailments or mechanical failures, production shortfalls may be such that the Liberty Power Group may still be forced to purchase power in the merchant market at prevailing rates to settle against a hedge.
Hedges currently put in place by the Liberty Power Group along with residual exposures to the market are detailed below:
The July 1, 2012 acquisition of the Sandy Ridge Wind Facility included a financial hedge, which commenced on January 1, 2013, for a 10 year period. The financial hedge is structured to hedge 72% of the Sandy Ridge Wind Facility’s expected production volume against exposure to PJM Western Hub current spot market rates. The annual unhedged production based on long term projected averages is approximately 44,000 MW-hrs annually. Therefore, each $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

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Western Hub current spot market rates. The annual unhedged production based on long term projected averages is approximately 42,000 MW-hrs annually.
The December 10, 2012 acquisition of the Senate Wind Facility included a physical hedge, which commenced on January 1, 2013, for a 15 year period. The physical hedge is structured to hedge 64% of the Senate Wind Facility’s expected production volume against exposure to ERCOT North Zone current spot market rates. The annual unhedged production based on long term projected averages is approximately 188,000 MW-hrs annually. Therefore, each $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.
A second hedge for the Minonk Wind Facility will commence on January 1, 2023, for a one year period. The financial hedge is structured to hedge 72% of the Minonk Wind Facility’s expected production volume against exposure to PJM Northern Illinois Hub current spot market rates. The annual unhedged production based on long term projected averages is approximately 189,000 MW-hrs annually.
Under each of the above noted hedges, if production is not sufficient to meet the unit quantities under the hedge, the shortfall must be purchased in the open market at market rates. The effect of this risk exposure could be material but cannot be quantified as it is dependent on both the amount of shortfall and the market price of electricity at the time of the shortfall.
In addition to the above noted hedges, from time to time the Liberty Power Group enters into short-term derivative contracts (with terms of one to three months) to further mitigate market price risk exposure due to production variability. As at September 30, 2018, the Liberty Power Group had no outstanding short-term hedges.
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 unaudited interim 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 $25.1 million. The Company has also exercised its option to acquire an additional 16.5% of equity interest in Atlantica from Abengoa for a purchase price of approximately $345.0 million based on a price of $20.90 per ordinary share. Accordingly, upon closing, each dollar change in the traded share price of Atlantica relative to the option price will impact Net Earnings by an additional $16.5 million.
OPERATIONAL RISK MANAGEMENT
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 the Liberty Power Group's hydroelectric facilities, water rights are generally owned by governments that reserve the right to control water levels, which may affect revenue.
The Liberty Utilities Group’s facilities are subject to rate setting by state regulatory agencies. The Liberty Utilities Group operates in 12 different states and therefore is subject to regulation from 12 different regulatory agencies. The time between the incurrence of costs and the granting of the rates to recover those costs by state regulatory agencies is known as regulatory lag. As a result of regulatory lag, inflationary effects may impact the ability to recover expenses, and profitability could be impacted. In order to mitigate this exposure, the Liberty Utilities Group seeks to obtain approval for regulatory constructs in the states in which it operates to allow for timely recovery of operating expenses. A fundamental risk faced by any regulated utility is the disallowance of costs to be placed into its revenue requirement by the utility's regulator. To the extent proposed costs are not allowed into rates, the utility will be required to find other efficiencies or cost savings to achieve its allowed returns.
The Liberty Utilities Group regularly works with its governing authorities to manage the affairs of the business, employing both local, state level, and corporate resources.
On December 22, 2017, 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%. Also, although deductibility of interest for regulated utilities has been retained, there is some uncertainty on whether holding company interest continues to be fully deductible and we are awaiting further guidance in this area. The change in corporate tax rates will have an impact

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on the financial operations and regulatory revenue requirements of most public utilities, including the Liberty Utilities Group. A reduction in the amount of interest expense deductible for income tax purposes could have an adverse effect on the Liberty Utilities Group's results of operations, financial condition and cash flows. The Liberty Utilities Group is proactively working with its various state regulators so that the impact of U.S. Tax Reform on customer rates is reflected in a manner that balances the rate impact of ongoing investments in utility infrastructure and recovery of operating costs with delivering the financial benefits from U.S. Tax Reform to customers.
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. While no date has been set, it is expected that the trial in the first phase will occur in the first quarter of 2019. 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.
Cycles and Seasonality
Liberty Power Group
The Liberty Power Group's hydroelectric operations are impacted by seasonal fluctuations and year to year variability of the available hydrology. These assets are primarily “run-of-river” and as such fluctuate with natural water flows. During the winter and summer periods flows are generally lower while during the spring and fall periods flows are generally higher. The ability of these assets to generate income may be impacted by changes in water availability or other material hydrologic events within a watercourse. Year-to-year the level of hydrology varies, impacting the amount of power that can be generated in a year.
The Liberty Power Group's wind generation facilities are impacted by seasonal fluctuations and year-to-year variability of the wind resource. During the fall through spring period, winds are generally stronger than during the summer periods. The ability of these facilities to generate income may be impacted by naturally occurring changes in wind patterns and wind strength.
The Liberty Power Group's solar generation facilities are impacted by seasonal fluctuations and year-to-year variability in the solar radiance. For instance, there are more daylight hours in the summer than there are in the winter, resulting in higher production in the summer months. The ability of these facilities to generate income may be impacted by naturally occurring changes in solar radiance.
The Company attempts to mitigate the above noted natural resource fluctuation risks by acquiring or developing generating stations in different geographic locations.
Liberty Utilities Group
The Liberty Utilities Group’s demand for water is affected by weather conditions and temperature. Demand for water during warmer months is generally greater than cooler months due to requirements for irrigation, swimming pools, cooling systems and other outside water use. If there is above normal rainfall or rainfall is more frequent than normal the demand for water may decrease, adversely affecting revenues.
The Liberty Utilities Group’s demand for energy from its electric distribution systems is primarily affected by weather conditions and conservation initiatives. The Liberty Utilities Group provides information and programs to its customers to encourage the conservation of energy. In turn, demand may be reduced which could have short term adverse impacts on revenues.
The Liberty Utilities Group's primary demand for natural gas from its natural gas distribution systems is driven by the seasonal heating requirements of its residential, commercial, and industrial customers. The colder the weather the greater the demand for natural gas to heat homes and businesses. As such, the natural gas distribution system's demand profiles typically peak in the winter months of January and February and decline 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 case proceedings. While not all regulatory jurisdictions have approved mechanisms to mitigate demand fluctuations, to date, the Liberty Utilities Group has successfully obtained regulatory approval to implement such decoupling mechanisms in 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.
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, performance and viability 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.
Energy generated by the Corporation is often sold under a long term PPA. PPAs generally contain customary terms including: the amount paid for energy from the project over the term of the agreement (which rate can be materially higher than prevailing market rates) and a requirement for the project to comply with technical standards and achieve commercial operation within time frames prescribed by the contract. A failure to achieve satisfactory construction progress and/or the occurrence of any permitting or other unanticipated delays at a project could result in a failure to comply with the applicable PPA requirements within the specified time frames. Remedies for failure to comply with material provisions of a PPA generally include, among other items, the potential termination of the agreement by the non-defaulting party.
For certain of its development projects, the Company relies on financing from third party tax equity investors. These investors typically provide funding upon the achievement of 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.
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.

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QUARTERLY FINANCIAL INFORMATION
The following is a summary of unaudited quarterly financial information for the eight quarters ended September 30, 2018:

(all dollar amounts in $ millions except per share information) | 4th Quarter 2017 |  | 1st Quarter 2018 |  | 2nd Quarter 2018 |  | 3rd Quarter 2018
Revenue | $ | 411.3 |  |  | $ | 494.8 |  |  | $ | 366.2 |  |  | $ | 366.5 |
Net earnings attributable to shareholders | 47.2 |  |  | 17.6 |  |  | 65.5 |  |  | 57.9 |
Net earnings per share | 0.11 |  |  | 0.04 |  |  | 0.14 |  |  | 0.12 |
Adjusted Net Earnings 1 | 67.0 |  |  | 141.0 |  |  | 50.9 |  |  | 49.7 |
Adjusted Net Earnings per share 1 | 0.16 |  |  | 0.32 |  |  | 0.11 |  |  | 0.10 |
Adjusted EBITDA 1 | 183.3 |  |  | 279.2 |  |  | 160.3 |  |  | 164.2 |
Total assets | 8,397.4 |  |  | 8,941.8 |  |  | 8,920.7 |  |  | 9,072.6 |
Long term debt 2 | 3,080.5 |  |  | 3,832.7 |  |  | 3,448.1 |  |  | 3,561.3 |
Dividend declared per common share | $ | 0.12 |  |  | $ | 0.12 |  |  | $ | 0.13 |  |  | $ | 0.13 |
| 4th Quarter 2016 |  | 1st Quarter 2017 |  | 2nd Quarter 2017 |  | 3rd Quarter 2017
Revenue | $ | 232.4 |  |  | $ | 421.7 |  |  | $ | 337.1 |  |  | $ | 353.7 |
Net earnings attributable to shareholders | 35.0 |  |  | 19.3 |  |  | 35.3 |  |  | 47.7 |
Net earnings per share | 0.12 |  |  | 0.05 |  |  | 0.09 |  |  | 0.12 |
Adjusted Net Earnings 1 | 38.8 |  |  | 66.5 |  |  | 39.5 |  |  | 52.0 |
Adjusted Net Earnings per share 1 | 0.12 |  |  | 0.19 |  |  | 0.09 |  |  | 0.13 |
Adjusted EBITDA 1 | 103.7 |  |  | 192.3 |  |  | 147.1 |  |  | 157.7 |
Total assets | 6,143.9 |  |  | 8,174.9 |  |  | 8,113.3 |  |  | 8,258.6 |
Long term debt 2 | 3,181.7 |  |  | 3,586.5 |  |  | 3,404.5 |  |  | 3,553.7 |
Dividend declared per common share | $ | 0.11 |  |  | $ | 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 $232.4 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.
DISCLOSURE CONTROLS AND PROCEDURES
APUC's management carried out an evaluation as of September 30, 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 September 30, 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.

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MANAGEMENT REPORT ON INTERNAL CONTROLS OVER FINANCIAL REPORTING
Management, including the CEO and the CFO, is responsible for establishing and maintaining internal control over financial reporting. Management, as at the end of the period covered by this interim filing, designed internal controls over financial reporting to provide reasonable, but not absolute, assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with U.S. GAAP. The control framework management used to design the issuer's internal control over financial reporting is that established in Internal Control - Integrated Framework (2013) issued by the Committee of Sponsoring Organizations of the Treadway Commission.
CHANGES IN INTERNAL CONTROLS OVER FINANCIAL REPORTING
For the nine months ended September 30, 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.
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 estimates relate to the useful lives and recoverability of depreciable assets, the measurement of deferred taxes and the recoverability of deferred tax assets, rate-regulation, unbilled revenue, pension and post-employment benefits, fair value of derivatives and fair value of assets and liabilities acquired in a business combination. Actual results may differ from these estimates.
APUC’s significant accounting policies and new accounting standards are discussed in notes 1 and 2 to the unaudited interim consolidated financial statements, respectively.
Presentation Currency
Effective January 1, 2018, the Company elected to change its presentation currency from Canadian dollars to U.S. dollars. Over 90% of APUC's consolidated revenue, Adjusted 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 NYSE. The Company believes that the change in reporting currency to U.S. dollars will provide more relevant information for the users of the unaudited interim financial statements as over 90% of the Company's consolidated revenues and assets are derived from operations in the United States.
The Company applied the change to U.S. dollar presentation retrospectively and restated the comparative 2017 financial information as if the U.S. dollar had been used as the reporting currency. Amounts denominated in Canadian dollars are denoted with "C$" immediately prior to the stated amount.

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