EX-99.1 2 a2017q4-exhibit991xaif.htm EXHIBIT 99.1 2017 Q4 AIF

ALGONQUIN POWER & UTILITIES CORP.
ANNUAL INFORMATION FORM
For the year ended December 31, 2017
March 7, 2018
All information contained in this AIF is presented as at December 31, 2017, unless otherwise specified. In this AIF, all dollar figures are in Canadian dollars, unless otherwise indicated.

Table of Contents

1. CORPORATE STRUCTURE | 6
1.1 Name, Address and Incorporation | 6
1.2. Intercorporate Relationships | 6
2. GENERAL DEVELOPMENT OF THE BUSINESS | 7
2.1 Three Year History and Significant Acquisitions | 8
2.1.1 Fiscal 2015 | 8
2.1.2 Fiscal 2016 | 9
2.1.3 Fiscal 2017 | 10
2.2 Recent Developments - 2018 | 12
3. DESCRIPTION OF THE BUSINESS | 13
3.1. Liberty Power Group | 13
3.1.1 Regulatory Regimes | 13
3.1.2 Description of Operations | 14
3.1.3 Specialized Skill and Knowledge | 22
3.1.4 Competitive Conditions | 22
3.1.5 Cycles & Seasonality | 22
3.2 Liberty Utilities Group | 23
3.2.1 Regulatory Regimes | 23
3.2.2 Description of Operations | 25
3.2.3 Specialized Skill and Knowledge | 32
3.2.4 Competitive Conditions | 32
3.2.5 Cycles & Seasonality | 32
3.3 Related Party Transactions | 33
3.4 Principal Revenue Sources | 33
3.5 Environmental Protection | 34
3.6 Employees | 35
3.7 Foreign Operations | 35
3.8 Economic Dependence | 35
3.9 Social or Environmental Policies | 35
3.10 Credit Ratings | 36
4. ENTERPRISE RISK FACTORS | 37
4.1 Risks Factors Relating to Operations | 38
4.2 Risk Factors Relating to Financing and Financial Reporting | 44
4.3 Risk Factors Relating to Regulatory Environment | 47
4.4 Risk Factors Relating to Strategic Planning and Execution | 49
5. DIVIDENDS | 53
5.1 Dividend Reinvestment Plan | 54
6. DESCRIPTION OF CAPITAL STRUCTURE | 54
6.1 Common Shares | 54

Table of Contents
(Continued)

6.2 Preferred Shares | 54
6.3 Convertible Debentures | 55
6.4 Shareholders' Rights Plan | 56
7. MARKET FOR SECURITIES | 56
7.1 Trading Price and Volume | 56
7.1.1 Common Shares | 56
7.1.2 Preferred Shares | 57
7.2 Prior Sales | 57
7.3 Escrowed Securities and Securities Subject to Contractual Restrictions on Transfer | 57
8. DIRECTORS AND OFFICERS | 58
8.1 Name, Occupation and Security Holdings | 58
8.2 Audit Committee | 61
8.2.1 Audit Committee Charter | 61
8.2.2 Relevant Education and Experience | 61
8.2.3 Pre-Approval Policies and Procedures | 61
8.3 Corporate Governance, Risk and Compensation Committees | 62
8.4 Bankruptcies | 62
8.5 Potential Material Conflicts of Interest | 62
9. LEGAL PROCEEDINGS AND REGULATORY ACTIONS | 62
9.1 Legal Proceedings | 62
9.2 Regulatory Actions | 62
10. INTEREST OF MANAGEMENT AND OTHERS IN MATERIAL TRANSACTIONS | 63
11. TRANSFER AGENTS AND REGISTRARS | 64
12. MATERIAL CONTRACTS | 64
13. INTERESTS OF EXPERTS | 64
14. ADDITIONAL INFORMATION | 65
SCHEDULE A - RENEWABLE - SELECTED HYDROELECTRIC, SOLAR AND WIND FACILITIES |
SCHEDULE B - SELECTED THERMAL - BIOMASS, COGENERATION, AND DIESEL FACILITIES |
SCHEDULE C - SELECTED WASTEWATER AND WATER DISTRIBUTION FACILITIES |
SCHEDULE D - SELECTED ELECTRICAL DISTRIBUTION FACILITIES |
SCHEDULE E - SELECTED NATURAL GAS DISTRIBUTION FACILITIES |
SCHEDULE F - MANDATE TO THE AUDIT COMMITTEE |
SCHEDULE G - GLOSSARY OF TERMS |

Caution Concerning 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 is not limited to: expectations regarding earnings and cash flow; statements relating to renewable energy credits expected to be generated and sold; tax credits expected to be available and/or received; the expected timeline for regulatory approvals; expectations with respect to the completion of the Atlantica transaction; the expected approval timing and purchase price of the Perris water distribution system transaction; the expected closing timing and amount of indebtedness to be assumed in relation to the St. Lawrence Gas Company, Inc. transaction; expectations and plans with respect to the Granite Bridge project; expectations with respect to revenues pursuant to energy production hedges; expected completion dates for projects under construction; expectations with respect to the Asbury Coal Power Plant; expected timing of post-closing adjustments related to the Long Sault Hydro Facility; the resolution of legal and regulatory proceedings; expected demand for renewable sources of power; government procurement opportunities; expected capacity of and energy sales from new energy projects; expected use of proceeds from the sale of common shares; business plans for APUC subsidiaries; and expected future base rates. All forward-looking information is given pursuant to the “safe harbour” provisions of applicable securities legislation.
The forecasts and projections that make up the forward-looking information contained herein are based on certain factors or assumptions which include, but are not limited to: the receipt of applicable regulatory approvals and requested rate decisions; the absence of material adverse regulatory decisions being received and the expectation of regulatory stability; the absence of any material equipment breakdown or failure; availability of financing on commercially reasonable terms and the stability of credit ratings of the Corporation and its subsidiaries; the absence of unexpected material liabilities or uninsured losses; the continued availability of commodity supplies and stability of commodity prices; the absence of sustained interest rate increases or significant currency exchange rate fluctuations; the absence of significant operational disruptions or liability due to natural disasters or catastrophic events; the continued ability to maintain systems and facilities to ensure their continued performance; the absence of a severe and prolonged downturn in general economic, credit, social and market conditions; the successful and timely development and construction of new projects; the absence of material capital project or financing cost overruns; sufficient liquidity and capital resources; the continuation of observed weather patterns and trends; the absence of significant counterparty defaults; the continued competitiveness of electricity pricing when compared with alternative sources of energy; the realization of the anticipated benefits of the Corporation’s acquisitions and joint ventures; the absence of a material change in political conditions or public policies and directions by governments materially negatively affecting the Corporation; the ability to obtain and maintain licenses and permits; the absence of a material decrease in market energy prices; the absence of material disputes with taxation authorities or changes to applicable tax laws; continued maintenance of information technology infrastructure and the absence of a material breach of cyber security; favourable relations with external stakeholders; and favourable labour relations.
The forward-looking information contained herein is subject to risks, uncertainties and other factors that could cause actual results to differ materially from historical results or results anticipated by the forward-looking information. Factors which could cause results or events to differ materially from current expectations include, but are not limited to: changes in general economic, credit, social and market conditions; changes in customer energy usage patterns and energy demand; global climate change; the incurrence of environmental liabilities; natural disasters and other catastrophic events; the failure of information technology infrastructure and cybersecurity; the loss of key personnel and/or labour disruptions; seasonal fluctuations and variability in weather conditions and natural resource availability; reductions in demand for electricity, gas and water due to developments in technology; reliance on transmission systems owned and operated by third parties; issues arising with respect to land use rights and access to the Corporation’s facilities; critical equipment breakdown or failure; terrorist attacks; fluctuations in commodity prices; capital expenditures; reliance on subsidiaries; the incurrence of an uninsured loss; a credit rating downgrade; an increase in financing costs or limits on access to credit and capital markets; sustained increases in interest rates; currency exchange rate fluctuations; restricted financial flexibility due to covenants in existing credit agreements; an inability to refinance maturing debt on commercially reasonable terms; disputes with taxation authorities or changes to

applicable tax laws; failure to identify appropriate projects to maximize the value of PTC qualified equipment; requirement for greater than expected contributions to post-employment benefit plans; default by a counterparty; inaccurate assumptions, judgments and/or estimates with respect to asset retirement obligations; failure to maintain required regulatory authorizations; changes to health and safety laws, regulations or permit requirements; failure to comply with and/or changes to environmental laws, regulations and other standards; compliance with new foreign laws or regulations; failure to identify attractive acquisition or development candidates necessary to pursue the Corporation’s growth strategy; delays and cost overruns in the design and construction of projects; loss of key customers; failure to realize the anticipated benefits of acquisitions; Atlantica or the Corporation’s anticipated 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 Factors”.
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 “Net Utility Sales”, “Net Energy Sales” and “Adjusted EBITDA” are used throughout this AIF. These terms are not recognized measures under GAAP. There is no standardized measure of “Net Utility Sales”, “Net Energy Sales” or “Adjusted EBITDA”; and 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 “Net Utility Sales”, “Net Energy Sales” and “Adjusted EBITDA” can be found in APUC’s MD&A for the year ended December 31, 2017 (which may be found on SEDAR at www.sedar.com and on EDGAR at www.sec.gov/edgar) under the headings “Liberty Power Group – 2017 Liberty Power Group Operating Results”, “Liberty Utilities Group – 2017 Fourth Quarter Operating Results”, “2017 Annual Operating Results”, and “Non-GAAP Performance Measures – Reconciliation of Adjusted EBITDA to Net Earnings”. Such calculations and analysis are incorporated by reference herein.
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 GAAP.
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 GAAP.

Adjusted EBITDA
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 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 Corporation. Where APUC manages the day to day operations of a facility and receives the majority of its economic benefits, the full operating profit of such facility is included in calculating the measure. 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 GAAP.

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1.CORPORATE STRUCTURE
1.1 Name, Address and Incorporation
Algonquin Power & Utilities Corp. (“APUC”) was originally incorporated under the Canada Business Corporations Act on August 1, 1988 as Traduction Militech Translation Inc. Pursuant to articles of amendment dated August 20, 1990 and January 24, 2007, the Corporation amended its articles to change its name to Société Hydrogenique Incorporée – Hydrogenics Corporation and Hydrogenics Corporation – Corporation Hydrogenique, respectively. Pursuant to a certificate and articles of arrangement dated October 27, 2009, the Corporation, among other things, created a new class of common shares, transferred its existing operations to a newly formed independent corporation, exchanged new common shares for all of the trust units of Algonquin Power Co. (“APCo”) and changed its name to Algonquin Power & Utilities Corp. The head and registered office of APUC is located at Suite 100, 354 Davis Road, Oakville, Ontario, L6J 2X1.
Unless the context indicates otherwise, references in this AIF to the “Corporation” refer collectively to APUC, its direct or indirect subsidiary entities and partnership interests held by APUC and its subsidiary entities.
1.2 Intercorporate Relationships
Most of the Corporation’s business is conducted through subsidiary entities, including those entities which hold project assets. The table on the following page excludes certain subsidiaries. The assets and revenues of the excluded subsidiaries did not individually exceed 10%, or in the aggregate exceed 20%, of the total consolidated assets or total consolidated revenues of the Corporation as at December 31, 2017. The voting securities of each subsidiary are held in the form of common shares, share quotas or partnership interests in the case of partnerships and their foreign equivalents, and units in the case of trusts.
The subsidiaries of APUC are grouped into two primary North American business units of the Corporation consisting of the Liberty Power Group and the Liberty Utilities Group. The following chart summarizes the major lines of business:

Liberty Power Group |  | Liberty Utilities Group
Hydro Electric Generation Solar Generation Thermal Co-Generation Wind Power Generation |  | Electric Utilities Natural Gas Utilities Water & Wastewater Utilities Natural Gas and Electric Transmission

Additional information on selected facilities owned by these business units is described in Schedules A, B, C, D, and E.

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The following table outlines the Corporation’s significant subsidiaries:

Significant Subsidiaries | Description | Jurisdiction | Ownership of Voting Securities
LIBERTY POWER GROUP
Algonquin Power Co. (dba Liberty Power) |  | Ontario | 100%
St. Leon Wind Energy LP (“St. Leon LP”) | Owner of the St. Leon Wind Facility | Manitoba | 100%
Algonquin Power Windsor Locks LLC | Owner of Windsor Locks Facility | Connecticut | 100%
Minonk Wind, LLC | Owner of the Minonk Wind Facility | Delaware | 100%1
Senate Wind, LLC | Owner of the Senate Wind Facility | Delaware | 100%1
GSG6, LLC | Owner of the Shady Oaks Wind Facility | Illinois | 100%
Odell Wind Farm, LLC | Owner of the Odell Wind Facility | Minnesota | 100%1
Deerfield Wind Energy, LLC | Owner of the Deerfield Wind Facility | Delaware | 100%1
LIBERTY UTILITIES GROUP
Liberty Utilities (Canada) Corp. (“LU Canada”) |  | Canada | 100%
Liberty Utilities Co. |  | Delaware | 100%
Liberty Utilities (CalPeco Electric), LLC | Owner of the CalPeco Electric System | California | 100%
Liberty Utilities (Granite State Electric) Corp. | Owner of the Granite State Electric System | New Hampshire | 100%
Liberty Utilities (EnergyNorth Natural Gas) Corp. | Owner of the EnergyNorth Gas System | New Hampshire | 100%
Liberty Utilities (Midstates Natural Gas) Corp. | Owner of natural gas distribution utility assets in Missouri, Iowa and Illinois | Missouri | 100%
Liberty Utilities (Peach State Natural Gas) Corp. | Owner of the Peach State Gas System | Georgia | 100%
Liberty Utilities (New England Natural Gas Company) Corp. | Owner of the New England Gas System | Delaware | 100%
Liberty Utilities (Park Water) Corp. (“Liberty Park Water”) | Owner of the Liberty Park Water System in Downey, California | California | 100%
Liberty Utilities (Apple Valley Ranchos Water) Corp. (“Apple Valley”) | Owner of the Apple Valley Water System | California | 100%
The Empire District Electric Company (“Empire”) | Owner of (i) electric and water distribution utility assets serving locations in Missouri, Kansas, Oklahoma and Arkansas, (ii) the Ozark Beach hydro facility in Missouri, the Riverton, Energy Center, and Stateline No. 1 natural gas-fired power generation facilities in Kansas and Missouri, the Asbury coal-fired power generation facility in Missouri and a 40% interest in the Stateline combined cycle gas facility in Missouri, and (iii) certain other generation facility and PPA interests. | Kansas | 100%
The Empire District Gas Company | Operator of a natural gas distribution utility in Missouri | Kansas | 100%
Liberty Utilities (Litchfield Park Water & Sewer) Corp. | Owner of the LPSCo System | Arizona | 100%

1 The Corporation holds 100% of the managing interests, with 100% of the non-managing interests held by third party partners.
2. GENERAL DEVELOPMENT OF THE BUSINESS
The Corporation 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 flow to support a growing dividend and share price

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appreciation. APUC also strives to achieve its results in the context of a moderate risk profile consistent with top-quartile North American power and utility operations.
The Corporation's operations are organized across two primary North American business units: the Liberty Power Group and the Liberty Utilities Group.
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 energy 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 and/or projects.
Liberty Utilities Group
The Liberty Utilities Group operates diversified regulated electricity, natural gas, water distribution and wastewater collection utility services. The Liberty Utilities Group provides safe, high quality, and reliable services to its customers through its nationwide portfolio of utility systems and delivers stable and predictable earnings to the Corporation. In addition to encouraging and supporting organic growth within its service territories, the Liberty Utilities Group delivers continued growth in earnings through accretive acquisition of additional utility systems.
2.1 Three Year History and Significant Acquisitions
The following is a description of the general development of the business of the Corporation over the last three fiscal years.
2.1.1 Fiscal 2015
Corporate
(i) $150 Million Bought Deal Offering of Common Shares
On December 2, 2015, APUC issued, on a bought deal basis, 14,355,000 Common Shares at a price of $10.45 per share for gross proceeds of approximately $150 million. Net proceeds of the offering were used to partially fund APUC's capital growth program, to reduce short-term debt and for general corporate purposes.
Liberty Power Group

(i) | Deerfield Wind Project Joint Venture

On October 19, 2015, the Liberty Power Group announced it had agreed to jointly develop the 150 MW Deerfield Wind Facility in Michigan with Renewable Energy Systems Americas Inc.
(ii) Great Bay Solar Project
On December 1, 2015, the Liberty Power Group announced the development of a new 75 MW contracted solar generation facility, located in Somerset County, Maryland. The facility is contracted under a 10 year PPA. The facility will also generate solar RECs which will be sold into the Maryland market. For more detail, see “Description of the Business – Liberty Power Group – Description of Operations – Business Development” below.
(iii) Completion of Bakersfield I Solar Project
On April 14, 2015, the Liberty Power Group achieved commercial operation of the 20 MW Bakersfield I Solar Facility located in Kern County, California. The electricity generated by the project is being sold under a 20 year PPA with a large investment grade electric utility. For more detail, see “Description of the Business – Liberty Power Group – Description of Operations – Solar Power Generating Facilities” below.

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Liberty Utilities Group
(i) Successful Rate Case Outcomes
A core strategy of the Liberty Utilities Group is to ensure an appropriate return on the rate base at its various utility systems. During 2015, the Liberty Utilities Group successfully completed several rate cases representing a cumulative annual revenue increase of approximately U.S. $18.1 million.
(ii) U.S. Debt Private Placement
On April 30, 2015, the Liberty Utilities Group financing entity entered into a note purchase agreement for the issuance of U.S. $160 million of senior unsecured 30 year notes bearing a coupon of 4.13% via a private placement in the U.S. The proceeds of the financing were used to partially finance the acquisition of the Liberty Park Water System and for general corporate purposes. The notes were issued in two tranches: U.S. $90 million were issued immediately on closing and U.S. $70 million were issued on July 15, 2015. The notes were assigned a rating of BBB High by DBRS. The financing was the fourth series of notes issued pursuant to the Corporation's master indenture.
2.1.2 Fiscal 2016
Corporate
(i) Financing Related to the Empire Acquisition
In the first quarter of 2016, in connection with the acquisition of Empire (the “Empire Acquisition”) discussed below, APUC and its direct wholly-owned subsidiary, LU Canada, entered into an agreement with a syndicate of underwriters under which the underwriters agreed to buy, on a bought deal basis, $1.15 billion aggregate principal amount of 5.00% convertible unsecured subordinated debentures (“Debentures”) of APUC (the “Debenture Offering”) and also obtained U.S. $1.6 billion in acquisition financing commitments from a syndicate of banks (the “Empire Acquisition Facility”). For more detail about the Empire business, see “Description of the Business – Liberty Utilities Group – Description of Operations” below.
(ii) Dual Listing of Algonquin Common Shares on the New York Stock Exchange
During the fourth quarter of 2016, APUC received approval to list the Common Shares for trading on the NYSE under the ticker symbol “AQN”. The Corporation has been a U.S. Securities and Exchange Commission registrant since 2009 and operates primarily in the United States. APUC shares continue to be listed on the TSX also under the ticker symbol “AQN”.
(iii) U.S. $235 Million Corporate Term Credit Facility
On January 4, 2016, the Corporation entered into a U.S. $235 million term credit facility with two U.S. banks. The proceeds of the term credit facility provided additional liquidity for general corporate purposes and acquisitions. The facility matures on July 5, 2018.
Liberty Power Group
(i) Acquisition of 75% interest in the Red Lily Energy Partnership
Effective April 12, 2016, the Liberty Power Group exercised its option to subscribe for a 75% equity interest in the Red Lily Wind Energy Partnership, a 26.4 MW wind energy facility (the “Red Lily Wind Facility”) located in southeastern Saskatchewan for which the Liberty Power Group provides operation and supervision services.
(ii) Completion of the Odell Wind Facility
On July 29, 2016, the 200 MW Odell Wind Facility achieved commercial operation. On August 5, 2016, the tax equity financing of approximately U.S. $180 million was completed and on September 15, 2016 the Liberty Power Group acquired control of the project. The Odell Wind Facility has a 20 year PPA with a large investment grade utility. For more detail, see “Description of the Business – Liberty Power Group – Description of Operations – Wind Power Generating Facilities” below.

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(iii) Purchase of Turbines to Safe Harbour Production Tax Credit Rate
At the end of 2016, the Liberty Power Group purchased approximately $75 million of turbine components that will qualify between 500 MW and 700 MW of new projects for 100% of the production tax credit (“PTC”). The full PTC is approximately U.S. $23 per MWh and subject to an annual adjustment for inflation. The PTC at the full rate is available to projects in the United States completed before the end of 2020 if they commenced construction prior to December 31, 2016 or have purchased components that qualify under the Internal Revenue Service safe harbor rules (“Full PTC Projects”). Projects other than Full PTC Projects will receive 80% of the applicable PTC rate if construction commences in 2017, 60% if construction commences in 2018, and 40% if construction commences in 2019. Securing access to the full PTC rate is an important competitive advantage in the U.S. market. The Liberty Power Group is currently evaluating projects to maximize the value of this equipment.
Liberty Utilities Group
(i) Acquisition of the Liberty Park Water System
On January 8, 2016, the Liberty Utilities Group closed a previously announced agreement to acquire a regulated water distribution utility holding company, Park Water Company, now known as Liberty Utilities (Park Water) Corp. (the “Liberty Park Water System”). The Liberty Park Water System owns and operates two regulated water utilities engaged in the production, treatment, storage, distribution, and sale of water in southern California and, at the time of closing, owned one regulated water utility in western Montana. Total consideration for the utility purchase was U.S. $341.3 million, which includes the assumption of approximately U.S. $91.8 million of existing debt.
The water utility located in western Montana was the subject of a condemnation lawsuit filed by the city of Missoula and has been the subject of certain related litigation and regulatory proceedings. Please see “Legal Proceedings and Regulatory Actions - Regulatory Actions” for a detailed description and discussion.
(ii) Successful Rate Case Outcomes
During 2016, the Liberty Utilities Group successfully completed several rate cases representing a cumulative annualized revenue increase of approximately U.S. $21.4 million.
2.1.3 Fiscal 2017
Corporate
(i) Completion of Financing Related to the Empire Acquisition
$1.15 Billion Bought Deal Offering of Convertible Unsecured Subordinated Debentures Represented by Instalment Receipts
Following the closing of the Empire Acquisition, the final instalment date was established as February 2, 2017 at which time APUC received the final instalment payment. To date, almost all of the Debentures had been converted into common shares of APUC, with APUC issuing approximately 108,384,716 common shares as a result of the conversion. The proceeds were used to repay a portion of APUC's bank facility drawn at closing of the Empire Acquisition Facility. For more detail about the Empire business, see “Description of the Business – Liberty Utilities Group – Description of Operations” below.
(ii) Extension of Dividend Reinvestment Plan
The Corporation announced on August 21, 2017 that eligible shareholders resident in the United States had then become able to enroll their Common Shares in the Corporation's shareholder dividend reinvestment plan (the “Reinvestment Plan”). Since its launch in 2011, the Reinvestment Plan was previously only available to residents of Canada.
(iii) Formation of Global Clean Energy and Water Infrastructure Joint Venture and Purchase of 25% Interest in Atlantica Yield plc
On November 1, 2017, APUC announced that it had entered into (a) a memorandum of understanding to create a joint venture (“AAGES”) with Seville, Spain-based Abengoa S.A. (“Abengoa”) to identify, develop, and construct clean energy and water infrastructure assets with a global focus. Concurrently with the agreement to create the AAGES joint venture, APUC announced that it had entered into a definitive agreement to purchase from Abengoa an indirect 25% equity interest in Atlantica Yield

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plc (“Atlantica”) for a total purchase price of approximately U.S. $608 million, or U.S. $24.25 per ordinary share of Atlantica, plus a contingent payment of up to U.S. $0.60 per-share payable two years after closing, subject to certain conditions. The transaction is expected to close in the first quarter of 2018. Closing is subject to customary closing conditions.
(iv) Bought Deal Offering of Common Shares
Coincident with the announcement of the Abengoa/Atlantica transaction on November 1, 2017, APUC announced a bought deal offering of Common Shares. The offering, including the exercise in full of the underwriters’ over-allotment option, closed on November 10, 2017. A total of 43,470,000 Common Shares were sold at a price of $13.25 per share for gross proceeds of approximately $576 million.
(v) Corporate Credit Facilities
During the third quarter of 2017, the Corporation’s senior unsecured bilateral revolving facility was increased from $65 million to $165 million and the maturity was extended to November 19, 2018. During the fourth quarter of 2017, the Corporation entered into a term credit agreement in the amount of U.S. $600 million with a maturity of December 21, 2018 to support the closing of its transactions with Abengoa and Atlantica, as described above.
Liberty Power Group
(i) Issuance of $300 million Senior Unsecured Debentures
On January 17, 2017, the Liberty Power Group issued $300 million of senior unsecured debentures bearing interest at 4.09% and with a maturity date of February 17, 2027. The debentures were sold at a price of $99.929 per $100.00 principal amount. Concurrent with the offering, the Liberty Power Group entered into a cross currency swap, coterminous with the debentures, to economically convert the Canadian dollar denominated offering into U.S. dollars. The net proceeds were used to partially finance the Odell Wind Facility, Deerfield Wind Facility and Bakersfield II Solar Facility.
(ii) Completion of Deerfield Wind Facility
On February 21, 2017, 150 MW Deerfield Wind Facility achieved commercial operation, on March 14, 2017, the Liberty Power Group acquired the remaining 50% interest in the project, and on May 10, 2017, tax equity financing of approximately U.S. $167 million was completed. The project has a 20 year PPA with a local electric distribution utility.
(iii) Great Bay Solar Project
On September 18, 2017, the Liberty Power Group entered into an equity capital contribution agreement with a third-party tax equity investor for a non-controlling interest in the Great Bay Solar Project. The tax equity investor will fund approximately U.S. $59 million.
(iv) Credit Facilities
On April 19, 2017, the Liberty Power Group entered into a $150 million senior unsecured bilateral revolving credit facility maturing on August 19, 2018. On October 6, 2017, the Liberty Power Group’s syndicated revolving credit facility was increased from $350 million to U.S. $500 million and the maturity was extended to October 6, 2022.
Liberty Utilities Group
(i) Completion of the Empire District Electric Acquisition
On January 1, 2017, the Liberty Utilities Group successfully completed its acquisition of Empire for an aggregate purchase price of approximately U.S. $2.4 billion including the assumption of approximately U.S. $0.9 billion of debt. Empire is a Joplin, Missouri based regulated electric, gas and water utility serving customers in Missouri, Kansas, Oklahoma, and Arkansas.
For more detail about the Empire business, see “Description of the Business – Liberty Utilities Group – Description of Operations” below. APUC has filed a business acquisition report dated March 10, 2017 in respect of the Empire Acquisition which may be found on SEDAR at www.sedar.com and on EDGAR at www.sec.gov/edgar.
(ii) Completion of Financing Related to the Empire Acquisition
On March 1, 2017, Liberty Utilities Group's financing entity entered into an agreement to issue U.S. $750 million of senior unsecured notes by way of private placement. The notes are of varying maturities ranging from 3 to 30 years with a weighted

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average life of approximately 15 years and an effective weighted average interest expense of 3.6% (inclusive of interest rate hedges). The closing of the offering occurred on March 24, 2017, with the proceeds used to repay the balance of the Empire Acquisition Facility and other existing indebtedness. For more detail about the Empire business, see “Description of the Business – Liberty Utilities Group – Description of Operations” below.
(iii) Completion of the Luning Solar Project
On February 15, 2017, the Liberty Utilities Group obtained control of a 50 MW solar generating facility located in Mineral County, Nevada (the “Luning Facility”) for approximately U.S. $110.9 million. On February 17, 2017, the final tranche of the tax equity financing of approximately U.S. $39.0 million was completed. The net capital cost of the project is included in the rate base of the CalPeco Electric System as energy produced from the project is being consumed by the utility's customers.
(iii) Approval to Acquire Perris Water Distribution System
On August 10, 2017, the Board approved the acquisition of two water distribution systems from the City of Perris, California for an anticipated purchase price of U.S. $11.5 million. The Perris City council approved the sale to the Liberty Utilities Group in July 2017 and the city’s residents approved the sale on November 7, 2017. Approval of the acquisition by the CPUC is expected in 2018.
(iv) Definitive Agreement to Acquire St. Lawrence Gas Company, Inc.
On August 31, 2017, the Liberty Utilities Group announced the entering into of a definitive agreement with Enbridge Gas Distribution Inc., a subsidiary of Enbridge Inc., to acquire St. Lawrence Gas Company, Inc. (“SLG”), a regulated natural gas distribution utility located in northern New York State, and its subsidiaries. The proposed transaction is structured as a stock purchase in exchange for a cash purchase price of U.S. $70 million less the total amount of outstanding SLG indebtedness (which will be assumed by the Liberty Utilities Group at closing and is currently expected to be approximately U.S. $10 million), and is subject to customary working capital adjustments. Closing of the acquisition remains subject to regulatory approval and other customary closing conditions, and is expected to occur in 2018.
(v) Granite Bridge Project Announcement
On December 4, 2017, the Liberty Utilities Group announced plans for a new infrastructure project designed to bring additional natural gas supply to New Hampshire’s residents and businesses. The project, called Granite Bridge, would bring natural gas from existing infrastructure located in New Hampshire’s Seacoast region to the central part of the state through an underground pipeline. The proposed Granite Bridge project would connect the existing Portland Natural Gas Transmission System and Maritimes and Northeast Pipeline facilities in Stratham with the existing Tennessee Gas Pipeline facilities in Manchester. The Granite Bridge project also includes a proposed Liquefied Natural Gas storage facility capable of storing up to two billion cubic feet of natural gas. The final project will be subject to approval from regulatory authorities.
(vi) Successful Rate Case Outcomes
During 2017, the Liberty Utilities Group successfully completed several rate cases representing a cumulative annualized revenue increase of approximately U.S. $20.4 million.
2.1.4 Recent Developments - 2018
Corporate
(i) Change to U.S. Dollar Reporting
APUC has determined that, effective with the first quarter of 2018, APUC's interim and annual consolidated financial statements will be reported in U.S. dollars.
Liberty Power Group
(i) Increase to Letter of Credit Facility
On February 16, 2018, the Liberty Power Group increased availability under its revolving letter of credit facility to U.S. $200 million. The facility continues to be a one year extendible facility.

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Liberty Utilities Group
(i) Liberty Utilities Credit Facilities
On February 23, 2018, the Liberty Utilities Group increased availability under its senior unsecured syndicated revolving credit facility from U.S. $200 million to U.S. $500 million and extended the maturity of such facility to 2023. The Liberty Utilities Group simultaneously canceled its U.S. $200 million revolving credit facility at Empire.
(ii) Pending Rate Case Filings
The Liberty Utilities Group has pending rate case filings in progress that represent an increase in rates in the amount of U.S. $44.4 million which are expected to be completed in 2018.
3. DESCRIPTION OF THE BUSINESS
3.1 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 facilities located across North America. The Liberty Power Group owns or has interests in hydroelectric, wind, solar, and thermal facilities with a combined generating capacity of approximately 120 MW, 1,050 MW, 40 MW, and 335 MW, respectively. Approximately 87% of the electrical output from the hydroelectric, wind, and solar generating facilities is sold pursuant to long term contractual arrangements which as of December 31, 2017 had a production-weighted average remaining contract life of approximately 15 years. Details with respect to the Liberty Power Group’s significant facilities and the term of material PPAs is set out in Schedules A and B.
3.1.1 Regulatory Regimes - Power Generation

(i) | Canada

Much of the electricity supplied within the Canadian provinces is generated by government-owned corporations, such as OPG and Hydro-Québec. Independent power producers, such as the Corporation, provide additional capacity and supply to the grids. In Canada, the provinces have legislative authority over the generation, transmission and distribution of electricity. This in turn means that each province may have different requirements for the business to comply with in respect of the projects it owns in each province.
Generally speaking, each province in which the Corporation operates has various pieces of legislation in effect with which the business must comply. These relate to the generation, transmission and distribution of electricity in the province, the administration of the electric system, as well as the creation and authority of various governmental agencies who have oversight of an aspect of the industry, such as the ISO and the provincial energy board, utilities commission or other similar authority responsible for rate-making and regulatory oversight of the industry. In addition, some provinces require a generator of electricity to be licensed and registered with the appropriate governmental authority and the Corporation must comply with the conditions of license or registration accordingly. In addition to the legal requirements, the system operators have promulgated market rules to be complied with within their operating jurisdictions and any codes, rules and standards of the applicable energy board or utilities commission must be complied with.

(ii) | United States

The power generation industry in the United States is regulated by the FERC under the U.S. Federal Power Act (“FPA”), the Energy Policy Act of 2005, the Public Utilities Regulatory Policies Act and the Public Utility Holding Company Act of 2005 (“PUHCA”).

(1) | Rate Regulation

All of the Liberty Power Group's operating U.S. power generation facilities are either: (1) exempt wholesale generators (“EWGs”); or (2) qualifying small power or cogeneration facilities (“QFs”). EWGs sell electricity exclusively in wholesale markets, while QFs with a power production capacity of 20 MW or less are exempt from most regulation under the FPA. There are two types

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of QFs: (1) qualifying small power production facilities; and (2) qualifying cogeneration facilities. In order to be a qualifying small power production facility, which includes hydro, geothermal, solar and biomass, the facility must meet the maximum size and fuel use criteria specified in FERC’s regulations. In order to be a qualifying cogeneration facility, the facility must meet the operating and efficiency criteria specified in FERC’s regulations. All of the Liberty Power Group’s operating U.S. power generation facilities that are EWGs possess FERC authorization to engage in sales for resale at market-based rates (“MBR Authority”). The QFs with a capacity greater than 20 MW also possesses MBR Authority. QFs with a capacity of 20 MW or less are not required to possess MBR Authority for their power sales, unless they are within a certain geographic proximity of one another. MBR Authority is available to EWGs and certain QFs and is obtained by showing that the generator and its affiliates do not possess vertical or horizontal market power in the relevant market. Once MBR Authority is obtained, the EWG or QF with a capacity greater than 20 MW, may sell its power into the relevant market at market-based rates. Each entity with MBR Authority must report its sales into the market by filing quarterly reports which details the relevant contracts used to sell power and the rates obtained for such power sales. QFs with a capacity of 20 MW or less are not required to file quarterly reports.

(2) | NERC

The Energy Policy Act of 2005 expanded FERC’s authority to impose mandatory reliability standards on the bulk electric system and to impose penalties on entities that manipulate the electric and natural gas markets. On June 20, 2006, NERC was certified by FERC as the Electric Reliability Organization for North America. NERC’s mission is to ensure the reliability and security of the North American Bulk Electric System. NERC accomplishes its mission through enforcement of mandatory regulation of reliability operating standards. NERC also annually assesses seasonal and long-term reliability; monitors the bulk power system through system awareness; and educates, trains, and certifies industry personnel. NERC’s area of responsibility spans the continental United States, Canada, and the northern portion of Baja California, Mexico. NERC is subject to oversight by FERC and governmental authorities in Canada. Some assets of the Liberty Power Group and the Liberty Utilities Group are subject to regulation by NERC.

(3) | PUHCA

The Corporation is also subject to the PUHCA. PUHCA and FERC’s implementing regulations impose certain books, records and accounting requirements on public utility holding companies. APUC is a public utility holding company and subject to such regulations. The Liberty Power Group's intermediate holding companies claims exemption from PUCHA under Title 18, Part 366.3 of the U.S. Code of Federal Regulations, which provides that a company that is a holding company solely by virtue of holding interests in QFs, EWGs and foreign utility companies is exempt from the books, records and accounting provisions of PUHCA and FERC’s associated regulations. Should any of the EWGs or QFs cease qualifying for such status by no longer meeting the regulatory requirements for qualification, then the exemption would no longer apply. At that time, the books, records and accounting requirements would then apply.
3.1.2 Description of Operations
Hydroelectric Generating Facilities

(i) | Production Method

A hydroelectric generating facility consists of a number of key components, including a dam, intake structure, electromechanical equipment consisting of a turbine(s) and a generator(s). A dam structure is required to create or increase the natural elevation difference between the upstream reservoir and the downstream tailrace, as well as to provide sufficient depth within the reservoir for an intake. Water flows are conveyed from the upstream reservoir to the generating equipment via a penstock or headrace canal and an intake structure. Turbine(s) and generator(s) transform the hydraulic energy into electrical energy. The water which has flowed through the hydraulic turbine(s) is discharged back to the natural watercourse. A transmission line is often required to interconnect a facility with the grid. The majority of hydroelectric generating facilities are also equipped with remote monitoring equipment, which allows the facility to be monitored and operated from a remote location.

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(ii) | Principal Markets and Distribution Methods

The principal markets in which the Liberty Power Group operates hydroelectric generating facilities in Canada are Alberta, Ontario, New Brunswick and Québec. In the U.S., the principal market is Maine. The majority of generated hydroelectricity is conveyed from the relevant facility to the purchasers under the terms of long term PPAs. The electricity is generally transferred by transmission line from the generating facility to the delivery point for the purchaser, and it is distributed through the grid to end user customers of the purchaser.

(1) | Alberta

The electrical power industry in Alberta is regulated by the EUA. The AESO was established under the EUA to provide a competitive, real-time spot market for electric energy. The AESO is non-discriminatory and open to any generator, marketer, distributor, importer or exporter that satisfies the qualification requirements established under the EUA and the rules and codes of practice of the AESO.

(2) | Ontario

The Ontario government develops the regulatory framework for wholesale and retail competition through the OEB. While transitional issues such as pricing and metering continue to be considered by the OEB, full competition in the wholesale and retail electricity market commenced on May 1, 2002.
The OEFC purchases the energy generated by the Ontario facilities and holds all rights, obligations and liabilities under the existing contracts. The Corporation's relevant subsidiary entities have also received a license to generate from the OEB as required by the Ontario Energy Board Act, 1998 (Ontario).

(3) | New Brunswick

Effective October 1, 2013, the New Brunswick government amended the provincial Electricity Act (New Brunswick), which resulted in the re-amalgamation of the NBSO with members of NB Power, a vertically-integrated group of companies, resulting in the transmission system operation functions of the NBSO being performed by NB Power’s Transmission and System Operator division.

(4) | Québec

Hydro-Québec is the primary electricity generator, transmitter, and distributor of electricity in the province of Québec; its sole shareholder is the Québec government. It uses mainly renewable generating options, in particular large hydro, and supports the development of other technologies, such as wind energy and biomass. It also sells power on wholesale markets in northeastern North America.

(iii) | Material Facilities

(1) Tinker Hydro Facility
The Tinker Hydro Facility is located approximately 8 km north of Perth-Andover, New Brunswick and is situated near the mouth of the Aroostook River. The facility has a total nameplate capacity of approximately 34.5 MW.
As part of the generation assets in New Brunswick and Northern Maine, the Liberty Power Group owns an electrical transmission system used to interconnect the Tinker Hydro Facility to the New Brunswick transmission network, provide transmission service to Perth Andover Electric Light Commission, and provide export/import capacity between Maine and New Brunswick.
The output of the Tinker Hydro Facility is actively marketed together with any applicable environmental attributes less any associated transportation costs. Additional energy and applicable environmental attributes are purchased from the market to supplement the energy generated from the Tinker Hydro Facility in order to service customer demand.
(2) Dickson Dam Hydro Facility
The Dickson Dam Hydro Facility is located 20 km west of the Town of Innisfail, Alberta. The Dickson Dam Hydro Facility is a 15.0 MW hydroelectric generating facility utilizing the infrastructure located at the Dickson Dam and powered by the water flows of the Red Deer River. The Liberty Power Group sells all of the power generated at the Dickson Dam Hydro Facility in

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the AESO at market rates. The Dickson Dam Hydro Facility is subject to a Use of Works Agreement with the Government of Alberta under which it has the right to utilize available water flows for generating power until March 31, 2030.
Wind Power Generating Facilities

(i) | Production Method

The energy of the wind can be harnessed for the production of electricity through the use of wind turbines. A wind energy system transforms the kinetic energy of wind into electrical energy that can be delivered to the electricity distribution system for use by energy consumers. When the wind blows, large rotor blades on the wind turbines are rotated, generating energy that is converted to electricity. Most modern wind turbines consist of a rotor mounted on a shaft connected to a speed increasing gear box and high speed generator. Monitoring systems control the angle of and power output from the rotor blades to ensure that the rotor blades are turned to face the wind direction, and generally to monitor the wind turbines installed at a facility.

(ii) | Principal Markets and Distribution Methods

The principal markets for the Liberty Power Group’s operational wind facilities in Canada are Manitoba for the St. Leon Wind Facilities, Saskatchewan for the Red Lily and Morse Wind Facilities, and Quebec for the Saint-Damase Wind Facility. The electricity generated by the wind turbines is transmitted to the transmission system of the purchaser, Manitoba Hydro in the case of the St. Leon Wind Facility and St. Leon II Wind Facility, SaskPower in the case of the Red Lily and Morse Wind Facility, and Hydro-Quebec in the case of the Saint-Damase Wind Facility. The principal markets for Liberty Power Group’s wind facilities in the United States are the PJM, MISO and ERCOT regional markets.

(1) | Manitoba

Historically, Manitoba Hydro had been exclusively responsible for the production of electricity in the province. Manitoba Hydro is a net exporter of electricity, mainly to Ontario and certain states of the United States. To date, the province has been able to utilize its large hydroelectric resources to satisfy internal and export requirements.

(2) | Saskatchewan

Saskatchewan’s electricity market remains under provincial government control and has not undergone any significant deregulation. SaskPower, the primary electricity utility in Saskatchewan, is wholly-owned by the province through the Crown Investments Corporation. SaskPower has set a target of 50% of generation capacity from renewables by 2030. As a result, SaskPower has a number of programs to encourage and solicit wind and other renewable power from independent producers.

(3) | Québec

Hydro-Québec's hydroelectric portfolio accounts for 99% of its electricity mix and, as such, the utility has encouraged the development of wind projects in the province in recent years.

(4) | Illinois and Pennsylvania

PJM is one of ten RTOs operating in North America. PJM, acting as a neutral, independent party, operates a competitive wholesale electricity market in all or parts of Delaware, Illinois, Indiana, Kentucky, Maryland, Michigan, New Jersey, North Carolina, Ohio, Pennsylvania, Tennessee, Virginia, West Virginia and the District of Columbia.

(5) | Michigan and Minnesota

MISO is an ISO, similar to an RTO, operating in fifteen U.S. states and the Canadian province of Manitoba. MISO assures consumers of unbiased regional grid management and open access to the transmission facilities through their functional supervision. MISO has interconnections with PJM, ERCOT, and other RTOs and ISOs. The fifteen states where MISO operates are: Arkansas, Illinois, Indiana, Iowa, Kentucky, Louisiana, Michigan, Minnesota, Mississippi, Missouri, Montana, South Dakota, North Dakota, Texas and Wisconsin.

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(6) | Texas

ERCOT, like PJM, is one of the ten RTOs operating in North America. ERCOT’s region occupies the entire Texas interconnection which occupies nearly all of the state of Texas. Unlike the other major NERC interconnections, the high voltage transmission and energy market within the Texas interconnection is operated by ERCOT as essentially a single power system instead of as a network of cooperating utility companies. The portion of the electric grid in the State of Texas that is under the administration of ERCOT was – and remains – essentially unconnected to electrical grids in other states and, in the absence of “electricity in interstate commerce,” does not fall under federal regulation.

(iii) | Material Facilities

(1) | St. Leon Wind Facility

The St. Leon Wind Facility is a 104 MW wind powered electrical generating facility located near St. Leon, Manitoba, 150 km southwest of Winnipeg. The St. Leon Wind Facility entered into a PPA with Manitoba Hydro effective June 17, 2006 under which all electricity produced is sold to Manitoba Hydro. The term of the PPA is 20 years, with a price renewal term of up to an additional five years.

(2) | Shady Oaks Wind Facility

The Shady Oaks Wind Facility is a 109.5 MW wind powered electrical generating facility located in Lee County, Illinois, 80 km west of Chicago. The Shady Oaks Wind Facility is party to a 20 year power sales contract with the largest electric utility in the state of Illinois, Commonwealth Edison. 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. Annual production is subject to contingent curtailment based on certain regulatory constraints of the electricity purchaser. The remaining generation and associated RECs are sold into the market.

(3) | Sandy Ridge Wind Facility

The Sandy Ridge Wind Facility is a 50 MW wind powered electrical generating facility located near Tyrone, Pennsylvania, 180 km east of Pittsburgh. Sandy Ridge Wind, LLC is party to a long term energy production hedge (the “Primary Energy Production Hedge”) with respect to the majority of production with J.P. Morgan Ventures Energy Corporation (“JPMVEC”), a wholly owned subsidiary of J.P. Morgan, having a term of 10 years beginning January 1, 2013 and is also party to an energy production hedge with another third party for production during 2023. Ancillary services, including capacity and RECs, are sold into the PJM market.

(4) | Minonk Wind Facility

The Minonk Wind Facility is a 200 MW wind powered electrical generating facility located near Minonk, IL, 200 km southwest of Chicago, IL. The Liberty Power Group first acquired an indirect interest in the Minonk Wind Facility on December 10, 2012. Minonk Wind, LLC is party to the Primary Energy Production Hedge with JPMVEC, having a term of 10 years beginning January 1, 2013 and is also party to an energy production hedge with another third party for production during 2023. Based on the JPMVEC contract quantity, approximately 73% of energy revenues are expected to be earned under the Primary Energy Production Hedge. Ancillary services, including capacity and RECs, are sold into the PJM market.

(5) | Senate Wind Facility

The Senate Wind Facility is a 150 MW wind powered electrical generating facility located near Graham, Texas, 200 km west of Dallas, Texas. Senate Wind, LLC is party to the Primary Energy Production Hedge with JPMVEC, having a term of 15 years beginning January 1, 2013. Based on the JPMVEC contract quantity, approximately 64% of energy revenues are expected to be earned under the Primary Energy Production Hedge. RECs are sold into the ERCOT market.

(6) | Odell Wind Facility

The Odell Wind Facility is a 200 MW wind powered electrical generating facility located near Windom, Minnesota, 230 km southwest of Minneapolis, Minnesota. Odell Wind Farm LLC has entered into a PPA with an investment grade utility under which all electricity and RECs produced at the facility are sold. The term of the PPA is 20 years.

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(7) Deerfield Wind Facility
The Deerfield Wind Facility is a 150 MW wind powered electrical generating facility located in central Michigan, 180 km north of Detroit, Michigan. All energy, capacity, and RECs produced at the facility are sold to a local electric distribution utility pursuant to a 20 year PPA.

(iv) | Renewable Energy Credits

RECs are tradeable commodities earned on the basis of 1 REC per MWh of electricity for wind generation facilities, and are used by utilities to satisfy compliance with RPS where necessary. These RPS mandates are set at a state level, and stipulate a certain amount of electricity to be generated from renewable sources by a specific year. Currently, the Minonk, Sandy Ridge, Senate, and Shady Oaks Wind Facilities each produce and sell RECs through bilateral contracts.
Solar Power Generating Facilities

(i) | Production Method

Solar power is the conversion of sunlight into electricity, either directly using photovoltaics or indirectly using concentrated solar power. The Corporation’s solar generation facilities, the Cornwall Solar Facility, Bakersfield I Solar Facility and the Bakersfield II Solar Facility, utilize photovoltaics which convert light into electric current using the photovoltaic effect. The array of a photovoltaic power system produces direct current power which fluctuates with the sunlight's intensity. For practical use, commercial installations convert this direct current generated power to alternating current through the use of inverters.

(ii) | Principal Markets and Distribution Methods

The principal markets for the Liberty Power Group’s operational solar facilities are Ontario for the Cornwall Solar Facility and California for the Bakersfield I Solar Facility and the Bakersfield II Solar Facility. The electricity generated by the solar panels is transmitted via electrical collection lines to the facility substation for subsequent delivery to the distribution/transmission system under control of the local distribution company and the ISO.

(1) | Ontario

The IESO is an independent, non-profit corporation that is responsible for the real time operation, long term planning and procurement for Ontario’s electricity system. The IESO is licensed by the OEB and it reports to the Ontario legislature through Ontario's Ministry of Energy.

(2) | California

The CAISO was formed in 1998 following a restructuring of the state electricity markets, and at the recommendation of the FERC. The CAISO operates as a non-profit public corporation responsible for operating the wholesale power system, maintaining the reliability of the grid, and planning for future demands. It is regulated by the FERC.

(iii) | Material Facilities

(1) | Bakersfield I Solar Facility

The Bakersfield I Solar Facility is a 20 MW ground mounted photovoltaic solar powered electric generating facility that uses single axis trackers to optimize the site’s generating efficiency. The site is located near Bakersfield, California, 150 km northwest of Los Angeles. The Bakersfield I Solar Facility achieved commercial operation in April 2015 and has a fixed rate PPA with an investment grade utility with a term of 20 years from commencement of commercial operation.

(iv) | Renewable Energy Credits

RECs are tradeable commodities earned on the basis of 1 REC per MWh of electricity for solar generation facilities, and are used by utilities to satisfy compliance with RPS where necessary. These RSP mandates are set at a state level, and stipulate a certain amount of electricity to be generated from renewable sources by a specific year.

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Thermal (Cogeneration) Electric Generating Facilities

(i) | Production Method

Cogeneration is the simultaneous production of electricity and thermal energy such as hot water or steam from a single fuel source. The steam produced is normally required by an associated or nearby commercial facility, while the electricity generated is sold to a utility or used within the facility. Cogeneration provides facilities with greater efficiency, greater reliability and increased process flexibility than conventional generation methods.

(ii) | Principal Markets and Distribution Methods

The principal markets for the Corporation’s cogeneration facilities are California and Connecticut. The electricity produced from these facilities is conveyed from the relevant facility to the electricity markets either under the terms of long-term contracts or according to ISO rules. In addition to grid sales of electricity and power, electricity and thermal energy are also sold to onsite or adjacent third party thermal host facilities for use in production.

(1) | California

The electric transmission system and wholesale markets in California are primarily regulated by the CPUC and FERC. The CAISO administers the wholesale electricity marketplace for the region.

(2) | Connecticut

The electricity markets and transmission systems in Connecticut are governed by the ISO-NE. The organization immediately assumed responsibility for managing the New England region’s electric bulk power generation and transmission systems and administering the region’s open access transmission tariff.

(iii) | Material Facilities

(1) | Sanger Thermal Facility

The Sanger thermal cogeneration facility is a 56 MW natural gas-fired generating facility located in Sanger, California. The facility has a firm capacity and energy PPA with an investment grade utility expiring in 2021. The agreement calls for delivery of 38 MW of firm capacity.

(2) | Windsor Locks Thermal Facility

The Windsor Locks thermal cogeneration facility (the “Windsor Locks Facility”) is a 71 MW natural gas-fired generating facility located in Windsor Locks, Connecticut. The Windsor Locks Facility supplies thermal steam energy and a portion of electrical generation to Ahlstrom Corporation pursuant to a ground lease and an energy services agreement. Payments under the energy services agreement are fully indexed to the cost of natural gas consumed by the Windsor Locks Thermal Facility. The additional installed capacity at the site is committed to the ISO-NE market in the day ahead energy market, and the capacity and reserve markets as appropriate.

(iv) | Renewable Energy Credits

RECs are tradable commodities earned on the basis of 1 REC per 1.33 MWh of electricity for thermal generation facilities, and are used by utilities to satisfy compliance with RPS where necessary. Currently, the Windsor Locks Thermal Facility is qualified for Class III CT RECs for a portion of its production. The facility produces and sells RECs through bilateral contracts.
Business Development

(i) | Strategy

The business development group works to identify, develop and construct new power generating facilities, as well as to identify and acquire operating projects that would be complementary and accretive to the Liberty Power Group’s existing portfolio. The business development group is focused on projects within North America and is committed to working proactively with all stakeholders including local communities. The Liberty Power Group’s approach to project development and acquisition is

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to maximize the utilization of internal resources while minimizing external costs. This approach allows projects to mature to the point where most major elements and uncertainties are quantified and resolved prior to the commencement of project construction. Major elements and uncertainties of a project include the signing of a PPA, obtaining the required financing commitments to develop the project, completion of environmental and other required permitting, and fixing the cost of the major capital components of the project. It is not until all major aspects of a project are secured that the Liberty Power Group's business development group will begin construction or execute an acquisition agreement.

(ii) | Principal Market Environment

The Liberty Power Group believes that future opportunities for power generation projects will continue to develop as new targets are set for renewable and other clean power generation projects.
Within Canada, the market is driven largely by provincial regulations, of which Alberta and Saskatchewan are expected to present the most immediate opportunities for the Corporation. The AESO was commissioned by the Government of Alberta to develop recommendations for the procurement of renewable sources of power that will allow the Province to meet its objective to have 30% of electricity generation by 2030 come from renewable sources. One round of procurements was completed in 2017, with just under 600 MW of contracts awarded. Two additional upcoming rounds of procurements are expected in 2018 and 2019. Additional smaller procurement opportunities are being considered, including a solar procurement process with Alberta Infrastructure.
In Saskatchewan, the vertically-integrated utility SaskPower has set a target of 50% of generation capacity to come from renewables by 2030, which is expected to lead to the development of approximately 1,600 MW of new wind energy generation and 120 MW of utility-scale solar generation. The first competition commenced in 2017, with contracts expected to be awarded in the second quarter of 2018.
Within the United States, the most notable stimulus for the development of renewable power is the federal renewable electricity PTCs, a per-kilowatt-hour tax credit for electricity generated by qualified energy resources, and the federal investment tax credit, a tax credit for qualified renewable energy facilities based upon a percentage of eligible capital costs. On December 18, 2015, the United States Congress approved a five-year extension to the 30 percent federal investment tax credit for solar energy properties and U.S. 2.3 cents per kilowatt-hour PTC (subject to certain inflation adjustments) for wind facilities. The federal investment tax credit for solar energy will remain at 30 percent through 2019, before it phases down gradually to 10 percent in 2022. The PTC for wind energy was maintained at U.S. 2.3 cents per kilowatt-hour (subject to certain inflation adjustments) for projects on which construction was commenced prior to the end of 2016 before phasing down 20 percent per year and being eliminated at the end of 2019. Federal tax reform passed late in 2017 had no direct impact on these incentive programs. Additionally, other incentives continue to be offered independently for the development of renewable sources of power at the state and local levels. State policies continue to be driven by RPS, which vary between states. As of 2017, 29 states plus Washington D.C. and three territories have adopted binding RPS targets, and eight additional states have taken on voluntary renewable portfolio goals. These targets range between 8.5% and 50% of retail sales to specific entities, to be achieved between 2015 and 2040.
The Liberty Power Group will continue to pursue development projects which provide the opportunity to exhibit accretive growth within these markets.

(iii) | Current Development or Construction Projects

The Liberty Power Group’s Development Division has successfully advanced a number of projects and has been awarded or acquired a number of PPAs. All of the projects contained in the table below meet the following criteria: a proven wind or solar resource, a signed PPA with a credit-worthy counterparty, and projected investment returns that meet or exceed APUC's investment return criteria.

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Project Name | Location | Size (MW) | Commercial Operation | PPA Term (Years from COD)
Projects in Construction |  |  |  |
Amherst Island Wind Project | Ontario | 75 | 2018 | 20
Great Bay Solar Project | Maryland | 75 | 2018 | 10
Total Projects in Construction |  | 150 |  |
Projects in Development |  |  |  |
Blue Hill Wind Project | Saskatchewan | 177 | 2019/20 | 25
Val-Éo Wind Project | Québec | 24 | 2018 | 20
Total Projects in Development |  | 201 |  |
Total in Construction and Development |  | 351 |  |

(1) | Amherst Island Wind Project

The Amherst Island wind project is a 75.0 MW wind powered electric generating development project located on Amherst Island near the village of Stella, approximately 15 km southwest of Kingston, Ontario (the “Amherst Island Wind Project”). The electricity to be generated by the project is being sold under a 20 year PPA awarded as part of the IESO FIT program. The project has a commercial operation date targeted for the second quarter of 2018.

(2) | Great Bay Solar Project

The Great Bay Solar Project is a 75.0 MW solar powered electric generating development project located in Somerset County in southern Maryland. All energy from the project will be sold to the U.S. Government Services Administration pursuant to a 10 year PPA, with a 10 year extension option. All RECs from the project will be retained by the project company and sold into the Maryland market. The project has a commercial operation date targeted for the first quarter of 2018.
(3) Blue Hill Wind Project
The Blue Hill wind project is a 177.0 MW wind powered electric generating development project located in Saskatchewan (the “Blue Hill Wind Project”). All of the energy from the project will be sold to SaskPower pursuant to a 25 year PPA awarded in 2016. The project is located in the rural municipality of Morse and Lawtonia, Saskatchewan.
The Blue Hill Wind Project will be developed as a single phase installation beginning in early 2019. The project requires final environmental approval and all other necessary permitting.

(4) | Val-Éo Wind Project

The Val-Éo wind project is anticipated to be a 125 MW wind powered electric generating development project located in the local municipality of Saint-Gideon de Grandmont, which is within the regional municipality of Lac-Saint-Jean-Est, Quebec (the “Val-Éo Wind Project”). The project proponents include the Val-Éo Wind Cooperative which was formed by community based landowners and the Liberty Power Group.
The Liberty Power Group has a 50% equity interest in the project. It is believed that the first 24 MW phase of the Val-Éo Wind Project will qualify as Canadian Renewable Conservation Expense and, therefore, the project will be entitled to a refundable tax credit equal to approximately $16.0 million.
The project will be developed in two phases. Phase I of the project is expected to be completed in 2018 and is expected to have a total capacity of 24 MW, with all energy from Phase I of the project to be sold to Hydro-Quebec pursuant to a 20 year PPA. Phase II of the project would entail the development of an additional 101 MW and would be constructed following the successful evaluation of the wind resource at the site, completion of satisfactory permitting and entering into appropriate energy sales arrangements. All land agreements, construction permits, and authorizations have been obtained for Phase I.

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The new schedule calls for Phase I construction to begin in the second quarter of 2018, with commissioning to occur in the fourth quarter of 2018.

(iv) | Future Development Projects – Greenfield Projects

The Corporation continues to pursue new development opportunities in addition to building upon an existing portfolio of green-field sites. These projects represent a diversified range of opportunities within hydro, solar, wind and natural-gas modes of generation and are located throughout North America.

3.1.3 | Specialized Skill and Knowledge

The Liberty Power Group's employees have extensive experience and contacts in the independent power industry in Canada and the United States. The energy from hydrology aspect of the business of the Liberty Power Group requires specialized knowledge of hydraulic turbines and their various components. This specialized knowledge is available to the Liberty Power Group in-house. The energy from wind aspect of the business of the Liberty Power Group requires specialized knowledge of wind turbines and their various components. This specialized knowledge is available to the Liberty Power Group in-house. On a more general level, the production of energy from all facilities requires specialized skill and knowledge, and the Liberty Power Group has employed various personnel who have such skill and knowledge.

3.1.4 | Competitive Conditions

Deregulation has increased the demand for privately generated power from a variety of sources including fossil fuels, waste, wind, water, and solar. With deregulation and opening of competition in the electricity marketplace, there should be an increase in the opportunity for the energy customer to choose the type of generation producing the electricity.
The U.S. Department of Energy has found that most utility customers want their utilities to pursue environmentally benign options for generating electricity and some customers are willing to pay extra to receive power generated by renewable resources. The Department of Energy believes that as deregulation and open competition evolve, the green power approach will help offset the relatively higher costs of renewable power compared to less costly gas-fired generation. Additionally, programs and policies are evolving at all government levels, allowing for the trading of greenhouse gas credits created by renewable energy projects to be seen as part of the eventual solution.
Unlike electricity generated by fossil fuels such as natural gas and coal which are subject to potentially dramatic and unexpected price swings due to disruptions in supply or abnormal changes in demand, the supply of hydroelectric, wind and solar power is not subject to commodity fuel price volatility or risk. In addition, generation of the above forms of power generation does not involve significant ongoing capital and operating costs to ensure strict compliance with environmental regulations, which is a significant advantage over power generated by burning waste or utilizing landfill gases.
Taking into account capital costs, wind and solar power has generally been more expensive than traditional forms of generated power. However, in recent years costs have decreased with the increased demand for renewable energy, market competitiveness and improvements in generating technology. With production tax incentives, investment tax incentives, RPS, and improved equipment capacity factors, both wind and solar energy have achieved parity with market pricing for electricity in many jurisdictions.
The Liberty Power Group believes that future opportunities for power generation projects will continue to arise given that many jurisdictions, both in Canada and the United States, continue to increase targets for renewable and other clean power generation projects.
The Liberty Power Group is ideally positioned to take advantage of this demand for increased renewable energy, given that a significant portion of its assets are from renewable sources.

3.1.5 | Cycles and Seasonality

(i) | Hydroelectric Generating Facilities

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

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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.

(ii) | Wind Power Generating Facilities

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.

(iii) | Solar Power Generating Facilities

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 Liberty Power Group attempts to mitigate the above noted natural resource fluctuation risks by acquiring or developing generating stations in different geographic locations.
3.2 Liberty Utilities Group
The Liberty Utilities Group operates a diversified portfolio of rate-regulated utilities throughout the United States that provide distribution services to approximately 762,000 connections in the natural gas, electric, water and wastewater sectors, with an approximate regional breakdown as follows:

| West | Central | East
Natural gas distribution | 0 | 127,000 | 210,000
Electrical distribution | 49,000 | 172,000 | 44,000
Water distribution | 90,000 | 28,000 | 0
Wastewater collection | 40,000 | 2,000 | 0
Total | 179,000 | 329,000 | 254,000

The regulated electrical distribution utility systems and related generation assets are located in the states of Arkansas, California, Kansas, Missouri, New Hampshire, and Oklahoma. The regulated natural gas distribution utility systems are located in the states of Georgia, Illinois, Iowa, Massachusetts, New Hampshire and Missouri. The regulated water distribution and wastewater collection utility systems are located in the states of Arizona, Arkansas, California, Illinois, Missouri and Texas. The Liberty Utilities Group operates a fleet of regulated electric generation assets with a net capacity of 1,424 MW.
Details with respect to significant Liberty Utilities Group facilities and certain rate and tariff information is set out in Schedules C, D and E.

3.2.1 | Regulatory Regimes - Utility Distribution Systems

Investor-owned utilities, whether water distribution and wastewater collection systems, electric distribution systems or gas distribution systems, are generally subject to economic regulation by the public utility commissions of the states in which they operate. The respective public utility commissions typically have jurisdiction over rates, service, accounting procedures, issuance of securities, acquisitions and other matters. The utilities generally operate under cost-of-service regulation as administered by these state authorities, using a test year in the establishment of rates for the utility and pursuant to this method the determination of the rate of return on approved rate base and deemed capital structure, together with all reasonable and prudent costs, establishes the revenue requirement upon which each utility’s customer rates are determined. Rates

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charged by these utilities are determined such that rates are set so as to provide the utilities with sufficient revenues to generate after-tax equity returns of approximately 8% to 12%. This oversight and other rules set by the state utility commissions are intended to ensure adequate supplies of water, electricity and natural gas together with financial security, transparency in the rate setting process and reasonable prices.

(i) | Water Distribution and Wastewater Collection Systems

Generally, water and wastewater providers in the United States operate as geographic monopolies within the areas in which they serve. A water or wastewater company is typically provided a service territory defined by a CPCN which imposes an exclusive right and duty to serve in the service territory. A CPCN is typically granted by a State agency, which also serves as an economic and service quality regulator for these water or wastewater service providers. Such agencies are charged with ensuring that water and wastewater services are provided at reasonable rates and quality to the Corporation’s customers. The agency must balance the interests of the utility customers as well as companies and their shareholders. Rates are approved by the agency to provide the water or wastewater company the opportunity, but not the guarantee, to earn a reasonable return on its investment after recovering its prudently incurred operating expenses.

(ii) | Electric Distribution Systems

The electricity industry is highly regulated in the United States. The industry is regulated under strict standards at multiple levels - federal, state and sometimes local. Under the FPA, FERC regulates interstate transmission, wholesale sales of electricity, corporate acquisitions and dispositions, securities and debt issuances, debt acquisitions, and reliability. State utility commissions perform a similar role, regulating sales of electricity to end-use customers, as well as financial stability and reliability.
Generally, electricity distribution companies in the United States operate as geographic monopolies within the areas in which they serve. An electricity distribution company is typically provided a CPCN which imposes an exclusive right and duty to serve in the service territory. The approval to serve is typically granted by a State agency, which also serves as an economic and service quality regulator for these electric service providers. Such agencies are charged with ensuring that electric services are provided at reasonable rates and quality to customers. The agency must balance the interests of the utility customers as well as companies and their shareholders. Rates are approved by the agency to provide the electric service company the opportunity, but not the guarantee, to earn a reasonable return on its investment after recovering its prudently incurred operating expenses.

(iii) | Natural Gas Distribution Systems

The natural gas industry is regulated at multiple levels - federal, state and sometimes local. Under the U.S. Natural Gas Act, FERC regulates interstate transmission and wholesale sales of gas. Interstate pipeline safety is regulated by the Department of Transportation. State utility commissions regulate retail distribution and sales of natural gas and intrastate pipelines. The federal pipeline safety requirements are often adopted by the state utility commissions and applied to intrastate pipelines and local distribution companies.
Generally, natural gas distribution companies in the United States operate as geographic monopolies within the areas in which they serve. A natural gas distribution company is provided a service territory which imposes an exclusive right and duty to serve in the service territory. The approval to serve is typically granted by a State agency, which also serves as an economic and service quality regulator for these natural gas service providers. Such agencies are charged with ensuring that natural gas services are provided at reasonable rates and quality to customers. The agency must balance the interests of the utility customers as well as companies and their shareholders. Rates are approved by the agency to provide the natural gas utility the opportunity, but not the guarantee, to earn a reasonable return on its investment after recovering its prudently incurred operating expenses.

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3.2.2 Description of Operations
Water Distribution and Waste Water Collection Systems

(i) | Method of Providing Services and Distribution Methods

A water utility services company provides regulated utility water supply and/or wastewater collection and treatment services to its customers.
A water utility sources, treats and stores potable water and subsequently distributes it to its customers through a network of buried pipes (distribution mains). The raw water for human consumption is sourced from the ground and extracted through wells or from surface waters such as lakes or rivers. The water is treated to potable water standards that are specified in Federal and State regulations and which are typically administered and enforced by a State or local agency. Following treatment, the water is either pumped directly into the distribution system or pumped into storage reservoirs from which it is subsequently pumped into the distribution system. This system of wells, pumps, storage vessels and distribution infrastructure is owned and maintained by the private utility. The fees or rates charged for water are comprised of a fixed charge component plus a variable fee based on the volume of water used. Additional fees are typically chargeable for other services such as establishing a connection, late fees and reconnects.
A wastewater utility collects wastewater from its customers and transports it through a network of collection pipes, lift stations and manholes to a centralized facility where it is treated, rendering it suitable for discharge to the environment or for reuse, usually as irrigation. The wastewater is ultimately delivered to a treatment plant. Primary treatment at the plant consists of the screening out of larger solids, floating material and other foreign objects and, at some facilities, grit removal. These removed materials are hauled to a landfill. Secondary treatment at the plant consists of biological digestion of the organic and other impurities which is performed by beneficial bacteria in an oxygen enriched environment. Excess and spent bacteria are collected from the bottom of the tanks digested and or dewatered and the resulting solids sent to landfill or to land application as a soil amendment. The treated water, referred to as “effluent”, is then used for irrigation or groundwater recharging or is discharged by permit into adjacent surface waters. The standards to which this wastewater is treated are specified in each treatment facility's operating permit and the wastewater is routinely tested to ensure its continuing compliance therewith. The effluent quality standards are based on Federal and State regulations which are administered and continuing compliance is enforced by the State agency to which Federal enforcement powers are delegated.

(ii) | Principal Markets and Regulatory Environments

The Liberty Utilities Group's water and wastewater facilities are located in the United States in the states of Arizona, Texas, Illinois, Missouri, Arkansas and California. The water and wastewater utilities are generally subject to regulation by the public utility commissions of the states in which they operate. The respective public utility commissions have jurisdiction with respect to rate, service, accounting procedures, issuance of securities, acquisitions and other matters. These utilities generally operate under cost-of-service regulation as administered by these state authorities. The utilities generally use a historic or forward looking test year in the establishment of rates for the utility and pursuant to this method the determination of the rate of return on approved rate base, recovery of depreciation on plant, together with all reasonable and prudent operating costs, establishes the revenue requirement upon which each utility’s customer rates are determined.
Rate cases ensure that a particular facility appropriately recovers its operating costs and has the opportunity to earn a rate of return on its capital investment as allowed by the regulatory authority under which the facility operates. The Corporation monitors the rates of return on each of its water and wastewater utility investments to determine the appropriate time to file rate cases in order to ensure it earns the regulatory approved rate of return on its investments. Rates are approved by the agency to provide the utility the opportunity, but not the guarantee, to earn a reasonable return on its investment after recovering its prudently incurred operating expenses.

(1) | Arizona

The ACC is the primary regulatory agency with jurisdiction over water and wastewater treatment utilities in Arizona. The ADEQ and the Arizona Department of Water Resources in conjunction with various county agencies (county health units) have primary jurisdiction respecting environmental regulation, water regulation and compliance.

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(2) | Texas

The Public Utility Commission of Texas is the primary regulatory agency with jurisdiction over water and wastewater treatment utilities in Texas. This regulatory responsibility was transferred from the Texas Commission on Environmental Quality to the Public Utility Commission of Texas on September 1, 2014. The Texas Commission on Environmental Quality has regulatory jurisdiction respecting environmental compliance, including implementing and enforcing the standards mandated by the federal Clean Water Act and the Safe Drinking Water Act, for all water and wastewater treatment service providers, including those owned and operated by municipalities.

(3) | Arkansas

The APSC is the primary regulatory agency with jurisdiction over the private and investor owned water utilities in Arkansas for rates and charges. The Arkansas Department of Health has regulatory jurisdiction respecting environmental compliance, including implementing and enforcing the standards mandated by the federal Clean Water Act and the Safe Drinking Water Act, for all water treatment service providers, including those owned and operated by municipalities. The Arkansas Department of Environmental Quality is the primary regulator for all discharge permits including wastewater treatment utilities in Arkansas.

(4) | California

The CPUC is the primary regulatory agency with jurisdiction over the private and investor owned water utilities in California for rates and charges. The SWRCB has regulatory jurisdiction respecting environmental compliance, including implementing and enforcing the standards mandated by the California Safe Drinking Water Act and Title 17 and 22 of the California Code of Regulations (California has primacy) for all water service providers, including those owned and operated by municipalities. The jurisdiction respecting drinking water for CPUC-regulated water providers is shared between the CPUC and SWRCB pursuant to a Memorandum of Understanding. The SWRCB is the primary regulator for all discharge permits from drinking water systems in California.
(iii) Material Facilities

(1) | Liberty Utilities (Litchfield Park Water & Sewer) Corp. Water & Wastewater Systems

The LPSCo System, located in and around the city of Goodyear 15 miles west of Phoenix, has a service area that includes the City of Litchfield Park and sections of the cities of Goodyear and Avondale as well as portions of unincorporated Maricopa County. The wastewater system’s Palm Valley Water Reclamation Facility has permitted treatment capacity of 5.8 million gallons per day.

(3) | Liberty Park Water System

Liberty Park Water owns and operates three regulated water utilities engaged in the production, treatment, storage, distribution, and sale of water in Southern California. Liberty Park Water provides, owns and operates the water system in central Los Angeles. Apple Valley (wholly-owned by Liberty Park Water) owns and operates the water system in Apple Valley, California.
Electric Distribution Systems

(i) | Method of Providing Services and Distribution Methods

Electric distribution is the final stage in the delivery system of providing electricity to end users. An electric distribution utility sources and distributes electricity to its customers through a network of buried or overhead lines. The electricity is sourced from power generation facilities. The electricity is transported from the source(s) of generation at high voltages through transmission lines and is then reduced through transformers to lower voltages at substations. The electricity from the substations is then delivered through distribution lines to the customers where the voltage is again lowered through a transformer for use by the customer.
The rates charged for electric distribution service are comprised of a fixed charge that recovers customer related costs, such as meter readings, and a variable rate component that recovers the cost of generation, transmission and distribution. Other

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revenues are comprised of fees for other services such as establishing a connection, late fee, reconnections, and energy efficiency programs.
The electrical distribution utilities located in California, New Hampshire, Missouri, Arkansas, Oklahoma and Kansas are subject to state regulation and rates charged by these utilities must be reviewed and approved by their respective State regulatory authorities.

(ii) | Principal Markets and Regulatory Environments

The Liberty Utilities Group operates electrical distribution systems in the states of Arkansas, California, Kansas, Missouri, New Hampshire and Oklahoma under a cost-of-service methodology. The utilities use either an historical test year, adjusted pro-forma for known and measurable changes, in the establishment of their rates, or prospective test years based on expenses expected to be incurred in future periods, which is the methodology utilized in California. Pursuant to these methods, the revenue requirement upon which rates are based is determined by applying an approved return on rate base, and adding depreciation, operating expenses and administrative and general expenses.
Rate cases ensure that a particular utility recovers its operating costs and has the opportunity to earn a reasonable rate of return on its capital investment as allowed by the regulatory authority under which the utility operates. The Corporation monitors the rates of return on its utility investments to determine the appropriate times to file rate cases in order to ensure it earns a reasonable rate of return on its investments. In the case of the CalPeco Electric System a rate case filing is mandatory every three years.

(1) | California

The CPUC regulates investor owned utilities in California and approves the rate of return and the rate base which affects the profitability of the utility.
The ECAC is an annual filing that sets rates to recover the next year’s fuel and purchased power costs in addition to setting rates to recover or refund any under/over recovery of previous year’s fuel and purchased power costs.
Post Test Year Adjustment Mechanism allows the CalPeco Electric System to update its rates annually by a cost inflation index. In addition, rates are updated to recover the return on investment and associated depreciation of major capital projects that are placed in service and meet a certain cost threshold.
The BRRBA removes the seasonal variations of the revenues and flattens the net revenue (minus fuel, purchased power, and ECAC) to a fixed monthly rate. This eliminates the risk of revenue variations associated with seasonal weather changes.

(2) | New Hampshire

The NHPUC is vested with general jurisdiction over electric, telecommunications, natural gas, steam, water and sewer utilities as defined in applicable legislation for issues such as rates, quality of service, finance, accounting, and safety. Utility companies are allowed to file distribution rate cases from time to time as the companies determine a need to request adjustments to base rates. There are a number of adjustment factors also in rates, for reliability enhancement programs, vegetation management, energy efficiency and low income programs, all of which are reconciled on an annual basis. Electricity distribution companies are also required to provide electricity commodity service for its customers who do not elect to take service from a competitive supplier. Costs for commodity service are recovered on a direct pass through basis.

(3) | Missouri

The Corporation's Missouri operations are regulated by the MPSC. The rates and fees for providing electric service to end users and recovering the authorized rate of return are in the form of a fixed monthly charge and a volumetric distribution charge. The rates billed to recover fuel costs are charged through the Fuel Adjustment Clause.

(4) | Arkansas

The APSC is the primary regulatory agency with jurisdiction over the investor owned electric utilities in Arkansas for rates and charges.

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(5) | Oklahoma

The OCC is the primary regulatory agency with jurisdiction over rates and charges of investor owned utilities in Oklahoma.

(6) | Kansas

The KCC is the primary regulatory agency with jurisdiction over rates and charges of investor owned utilities in Kansas.

(iii) | Material Facilities

(1) | CalPeco Electric System

The CalPeco Electric System provides electric distribution service to the Lake Tahoe basin and surrounding areas. The service territory, centered on a highly popular tourist destination, has a customer base spread throughout Alpine, El Dorado, Mono, Nevada, Placer, Plumas and Sierra Counties in northeastern California. CalPeco Electric System’s connection base is primarily residential. Its commercial connections consist primarily of ski resorts, hotels, hospitals, schools and grocery stores.
The Corporation has entered into a multi-year services agreement with NV Energy commencing January 2016. The PPA obligates NV Energy to use commercially reasonable efforts to supply the CalPeco Electric System with sufficient renewable power to, combined with the Luning Facility, satisfy the current California Renewables Portfolio Standard requirement for the five year term of the PPA. The CalPeco Electric System has received approval from CPUC to recover the costs it will incur under this agreement. The CalPeco Electric System has authorization for rate recovery of the costs that the Calpeco Electric System has or will incur to acquire, own, and operate the Luning Facility. On January 31, 2017, the Federal Energy Regulatory Commission authorized transactions between the Luning Facility and the CalPeco Electric System pursuant to the PPA with NV Energy. The system is also subject to FERC regulation.

(2) | Granite State Electric System

The Granite State Electric System provides distribution service in southern and northwestern New Hampshire, centered around operating centers in Salem in the south and Lebanon in the northwest. The Granite State Electric System’s customer base consists of a mixture of residential, commercial and industrial customers.
Granite State Electric System is required to provide electric commodity supply for all customers who do not choose to take supply from a competitive supplier (“Default Service”) in the New England power market, and is allowed to fully recover its costs for the provision and administration of Default Service under the Default Service Adjustment Provision, as approved by the NHPUC. The Granite State Electric System must file with the NHPUC twice a year to adjust for market prices of power purchased, and is also subject to FERC regulation.

(3) | Empire District Electric System

Based in Joplin, Missouri, Empire is a regulated utility providing electric, natural gas and water service in parts of Missouri, Kansas, Oklahoma and Arkansas. As part of its electric segment, it provides water service to three towns in Missouri. The vertically-integrated regulated electricity operations of Empire represent the majority of its operating revenues and assets. The largest urban area served is the city of Joplin, Missouri, and its immediate vicinity. The Empire District Gas Company is a wholly owned subsidiary engaged in the distribution of natural gas in Missouri. The largest urban area served by Empire’s gas operations is the city of Sedalia. Empire also operates a fiber optics business. The utility portions of the business are subject to regulation by the MPSC, the KCC, the OCC, the APSC and the FERC.
Natural Gas Distribution Systems

(i) | Method of Providing Services and Distribution Methods

Natural gas is a fossil fuel composed almost entirely of methane (a hydrocarbon gas) usually found in deep underground reservoirs formed by porous rock. In making its journey from the wellhead to the customer, natural gas may travel thousands of miles through interstate pipelines owned and operated by pipeline companies. Along the route, the natural gas may be stored underground in depleted oil and gas wells or other natural geological formations for use during seasonal periods of high demand. Interstate pipelines interconnect with other pipelines and other utility systems, and offer system operators flexibility

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in moving the gas from point to point. The interstate pipeline companies are regulated by the FERC. Typically, the distribution network operates pipelines (including transmission and distribution pipelines), gate stations, district regulator stations, peak shaving plants and natural gas meters. The gas distribution utilities owned by the Liberty Utilities Group are subject to state regulation and rates charged by these facilities may be reviewed and altered by the State regulatory authorities from time to time.

(ii) | Principal Markets & Regulatory Environments

The Liberty Utilities Group owns and operates natural gas distribution systems, under cost-of-service regulation in the states of Illinois, Iowa, Missouri, Georgia, Massachusetts and New Hampshire. The natural gas utilities use a test year to determine distribution rates for the utility. Pursuant to this method, the revenue requirement upon which rates are based is determined by applying an approved return on rate base, and adding depreciation, operating expenses, and administrative and general expenses.
Rate cases ensure that a particular facility appropriately recovers its operating costs and has the opportunity to earn a reasonable rate of return on its capital investment as allowed by the regulatory authority under which the facility operates. The Corporation monitors the rates of return on its utility investments to determine the appropriate times to file rate cases in order to ensure it earns a reasonable rate of return on its investments.

(1) | New Hampshire

In New Hampshire, gas utilities are regulated by the NHPUC. The NHPUC is vested with general jurisdiction over electric, telecommunications, natural gas, steam, water and sewer utilities as defined in applicable legislation for issues such as rates, quality of service, finance, accounting, and safety. The rates and fees for providing gas service to end users and recovering the authorized rate of return are in the form of a fixed monthly charge and a volumetric distribution charge. The rates billed to recover gas costs are in the form of the tariffed PGA.

(2) | Illinois

The Liberty Utilities Group's Illinois operations are regulated by the Illinois Commerce Commission. The rates and fees for providing gas service to end users and recovering the authorized rate of return are in the form of a fixed monthly charge and a volumetric distribution charge. The rates billed to recover gas costs are in the form of the tariffed PGA.

(3) | Iowa

The Liberty Utilities Group's Iowa operations are regulated by the Iowa Utilities Board. The rates and fees for providing gas service to end users and recovering the authorized rate of return are in the form of a fixed monthly charge and a volumetric distribution charge. The rates billed to recover gas costs are in the form of the tariffed PGA.

(4) | Missouri

The Liberty Utilities Group's Missouri utility operations are regulated by the MPSC. The rates and fees for providing gas service to end users and recovering the authorized rate of return are in the form of a fixed monthly charge and a volumetric distribution charge. The rates billed to recover gas costs are in the form of the tariffed PGA.

(5) | Georgia

The Liberty Utilities Group's Georgia operations are regulated by the Georgia Public Service Commission. The rates and fees for providing gas service to end users and recovering the authorized rate of return are in the form of a fixed monthly charge and a volumetric distribution charge. The rates billed to recover gas costs are in the form of the tariffed PGA.

(6) | Massachusetts

The Liberty Utilities Group's Massachusetts operations are regulated by the Commonwealth of Massachusetts. The MDPU has regulatory jurisdiction over all public utilities and common carriers operating in the Commonwealth, which jurisdiction includes the establishment of approved tariffed rates for the purpose of billing customers. The rates and fees for providing

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gas service to end users and recovering the authorized rate of return are in the form of a fixed monthly charge and a volumetric distribution charge. The rates billed to recover gas costs are in the form of the tariffed PGA.

(iii) | Material Facilities

(1) | EnergyNorth Gas System

The EnergyNorth Gas System is a regulated natural gas utility providing natural gas distribution services in 30 communities covering five counties in New Hampshire. Its franchise service area includes the communities of Nashua, Manchester and Concord, New Hampshire. The EnergyNorth Gas System's customer base consists of a mixture of residential, commercial, industrial and transportation customers.
The EnergyNorth System in New Hampshire recently filed two applications with the New Hampshire Public Utilities Commission to obtain the franchise rights to provide gas to new territories. One was filed in November 2016 seeking approval to obtain the franchise rights to the Town of Hanover and City of Lebanon. A settlement has been reached in this docket and the Corporation is currently awaiting a final decision order. Another application was filed in August 2015 seeking the franchise rights to the towns of Pelham and Windham, which has been approved by the NHPUC.

(2) | Empire District Gas System

EDG is engaged in the distribution of natural gas in Missouri and serves approximately 43,000 customers. A PGA allows EDG to recover from its customers, subject to audit and final determination by regulators, the cost of purchased gas supplies and related carrying costs associated with EDG's use of natural gas financial instruments to hedge the purchase price of natural gas. This PGA allows EDG to make rate changes periodically (up to four times) throughout the year in response to weather conditions and supply demands, rather than in one possibly extreme change per year.

(3) | Peach State Gas System

The Peach State Gas System is a regulated natural gas system providing natural gas distribution services in 13 communities covering six counties in Georgia. Its franchise service area includes the communities of Columbus, Gainesville, Waverly Hall, Oakwood, and Hamilton, GA. The Peach State Gas System's customer base consists of a mixture of residential, commercial, industrial and transportation customers.
The Peach State Gas System’s rates are reviewed and updated annually through a tariff provision called the GRAM. This mechanism allows for the annual review of cost recoveries and the setting of rate base returns with a target of 10.7% return on equity and a range of 10.5% to 10.9%. The Peach State Gas System also files an annual Pipe Replacement Program revision to adjust the rates collected for capital costs incurred to replace cast iron and bare steel pipe in its system.
Georgia allows full recovery of all gas costs (including commodity price, transportation, reservation and demand costs, hedging costs, storage costs). The PGA requires a change in rates at least every three months.

(4) | New England Gas System

The New England Gas System is a regulated natural gas utility providing natural gas distribution services in six communities located in the southeastern portion of Massachusetts. The New England Gas System's customer base consists of a mixture of residential, commercial, and industrial customers.
The cost of gas is fully recoverable from customers through the Gas Adjustment Factor (“GAF”) when billed to “firm” gas customers included in approved tariffs by the MDPU. The GAF is adjusted twice annually and more frequently under certain circumstances.
(5) Midstates Gas System
The Midstates Gas System owns regulated natural gas utilities providing natural gas distribution services to approximately 190 communities in the states of Illinois, Iowa and Missouri, with a mix of residential, commercial, industrial and transportation customers. The franchise service area includes the communities of Virden, Vandalia, Harrisburg and Metropolis in Illinois, Keokuk in Iowa, and Butler, Kirksville, Canton, Hannibal, Jackson, Sikeston, Malden and Caruthersville in Missouri.

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Illinois allows full recovery of all gas costs (including commodity price, transportation, reservation and demand costs, hedging costs, and storage costs). The rate is adjusted monthly with an annual reconciliation based on the calendar year. Iowa allows full recovery of all gas costs (including commodity price, transportation, reservation and demand costs, hedging costs, and storage costs). The rate is adjusted monthly with an annual reconciliation based on the twelve months ended August of each year. Missouri allows full recovery of all gas costs (including commodity price, transportation, reservation and demand costs, hedging costs, and storage costs). The rate is adjusted annually (in fourth quarter) with allowance to file quarterly.
Natural Gas and Electric Transmission

(i) | Method of Providing Services and Distribution Methods

Pipelines offer a variety of services under their FERC tariffs to include firm and interruptible transportation, along with other services to provide commercial markets additional flexibility. Some examples of these types of services would be park and loan, pooling and balancing services. In addition, firm service tariff features would also provide additional features to support secondary market activity to include, but not limited to capacity assignment, capacity releases, segmentation and renewal options.

(ii) | Principal Markets & Regulatory Environments

Interstate natural gas pipeline transmission assets are regulated primarily by the FERC under the Natural Gas Act. Under this framework, this agency authorizes and certifies all construction, and or abandonment of interstate gas pipeline facilities, requires certificate holders, once operational, to establish and maintain an OATT and publicly post capacity available for transportation, and the agency periodically reviews, under just and reasonable standards, the tariff rates to be charged by the certificate holder. In addition, the FERC prescribes operating and safety standards to be followed along with other federal agencies such as Department of Transportation and the Occupational Safety and Health Administration.
The Empire transmission facilities are located within a four state area of Missouri, Kansas, Oklahoma, and Arkansas and Empire is a member of the SPP which spans an area from the Canadian border in Montana and North Dakota in the north to parts of New Mexico, Texas and Louisiana in the south. The transmission facilities are offered for service under an OATT approved by the FERC and administered by SPP. Service requests are placed in the SPP Open Access Same-Time Information System (OASIS) and is evaluated by SPP for available capacity. SPP determines who is offered available transmission capacity subject to the SPP Tariff and SPP Market Rules and is offered on a non-discriminatory basis. Service requests can be either point-to-point or network service, where network service is used for serving electric load. Empire is subject to four different states regulatory bodies, the SPP regional entity for NERC compliance, SPP Market Rules, and the FERC.
Business Development
The Liberty Utilities Group's strategy is to grow its business organically and through business development activities while using prudent acquisition criteria.
Granite Bridge
On December 4, 2017, the Liberty Utilities Group announced plans for a new infrastructure project designed to bring additional natural gas supply to New Hampshire’s residents and businesses. The project, called Granite Bridge, would bring natural gas from existing infrastructure located in New Hampshire’s Seacoast region to the central part of the State through an underground pipeline. The proposed Granite Bridge project would connect the existing Portland Natural Gas Transmission System and Maritimes and Northeast Pipeline facilities in Stratham with the existing Tennessee Gas Pipeline facilities in Manchester. The Granite Bridge project also includes a proposed Liquefied Natural Gas storage facility capable of storing up to two billion cubic feet of natural gas. The final project will be subject to approval from regulatory authorities.
Empire District Electric Wind Projects
On October 31, 2017, the Liberty Utilities Group filed a plan with regulators to expand its wind energy resource. The plan calls for the development of up to 800 MW of new wind generation strategically located in or near its service territory by the

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end of 2020. As part of this proposed plan, the energy generated by the wind farm is expected to replace the energy currently generated by the Asbury Coal Power Plant. This plan is subject to regulatory approval, which is currently expected to be received by the summer of 2018.
3.2.3 Specialized Skill and Knowledge
The Liberty Utilities Group requires specialized knowledge of the utility systems served including electrical, gas or water and waste water distribution. Upon acquiring a new utility system the Liberty Utilities Group will typically retain the existing employees with such specialized skill and knowledge. In addition, the Liberty Utilities Group will add, when required, additional trained utility personnel at its corporate offices to support the expanded portfolio of utility assets.
3.2.4 Competitive Conditions
The Liberty Utilities Group’s businesses have geographic monopolies in their service territories. The Liberty Utilities Group has developed significant in-house regulatory expertise in order to effectively interact with the state regulators in the various jurisdictions in which it operates. The Liberty Utilities Group believes that the relationship with regulators is unique to each state and therefore is best delivered by local managers who work in the service territory. The local regulatory teams meet with regulatory agencies on a regular basis to review regulatory policies, service delivery strategies, operating results and rate making initiatives.
3.2.5 Cycles and Seasonality

(i) | Water and Wastewater Systems

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 Corporation attempts to mitigate the above noted risks by seeking regulatory mechanisms during rate case proceedings. Certain jurisdictions have approved constructs to mitigate demand fluctuations. For example, the Central Basin and Apple Valley facilities in California, a weather normalization adjustment is applied to customer bills that adjusts commodity rates to stabilize the revenues of the utility for changes in billing units attributable to weather patterns. Not all regulatory jurisdictions in which the Liberty Utilities Group operates have approved mechanisms to mitigate demand fluctuations.
Water distribution facilities depend on an adequate supply of water to meet present and future demands of customers. Drought conditions could interfere with sources of water supply used by the utilities and affect their ability to supply water in sufficient quantities to existing and future customers. An interruption in the water supply could have an adverse effect on the results of operations of the utilities. Government restrictions on water usage during drought conditions could also result in decreased demand for water, even if supplies are adequate, which could adversely affect revenues and earnings.

(ii) | Electricity Systems

The CalPeco Electric System’s demand for energy sales are primarily affected by weather conditions. Above normal snowfall in the Lake Tahoe area brings more tourists with an increased demand for electricity by small commercial customers. The CalPeco Electric System has implemented a BRRBA rate mechanism that removes the seasonal variations of revenues and flattens the net revenue (gross revenues less fuel, purchased power, and the ECAC deferral) to a fixed monthly amount. This mechanism eliminates the risk of revenue variations associated with seasonal weather changes.
The Granite State Electric System experiences peak loads in both the winter and summer seasons, due to heating and cooling loads associated with New England weather. The competitive market for power supply is managed by the ISO-NE. The Default Service price for power may fluctuate as a result of the weather, but those costs are passed through directly to customers.
The Granite State Electric System offers a comprehensive menu of energy efficiency programs in New Hampshire that, in turn, may reduce the demand for energy. These programs are funded via a charge in distribution rates known as the systems benefit charge, which applies to all utilities. This mechanism provides for an annual reconciliation of costs. The company has an opportunity to earn a performance incentive if it is successful in achieving its annual energy efficiency targets.

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The Empire District Electric System experiences peak loads in both the winter and summer seasons, due to heating and cooling loads associated with weather in its service territory. The Default Service price for power may fluctuate as a result of the weather, but those costs are passed through directly to customers and as a result does not have a material financial impact.

(iii) | Natural Gas Systems

The Liberty Utilities Group's primary demand for natural gas from its natural gas distribution systems is driven by the seasonal heating requirements of its residential, commercial, and industrial customers. The colder the weather, the greater the demand for natural gas to heat homes and businesses. As such, the natural gas distribution systems' demand profiles typically 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.
The Liberty Utilities Group attempts to mitigate the above noted risks by seeking regulatory mechanisms during rate case proceedings. Certain jurisdictions have approved constructs to mitigate demand fluctuations. For example, at the Peach State Gas System in Georgia, 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. Not all regulatory jurisdictions in which the Liberty Utilities Group operates have approved mechanisms to mitigate demand fluctuations.
3.3 Related Party Transactions
(i) Equity-method investments
The Corporation provides administrative services to its equity-method investees and is reimbursed for incurred costs. To that effect, the Corporation charged its equity-method investees $6.0 million in 2017 as compared to $3.3 million during the same period in 2016.
(ii) Long Sault Hydro Facility
Effective December 31, 2013, APUC acquired the shares of APCI 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 is expected to be settled in 2018.
3.4 Principal Revenue Sources
APUC owns, directly or indirectly, interests in renewable generation facilities, thermal generation facilities, electrical distribution utilities, natural gas and propane distribution utilities, and water distribution and wastewater utilities.
The following provides a breakdown of the Corporation’s total revenue by percentage for the years ended December 31, 2016 and December 31, 2017:

| % Total Revenue
| December 31, 2017 | December 31, 2016
Non-regulated energy sales | 14.3% | 22.2%
Utility electricity sales & distribution | 50.0% | 20.8%
Utility natural gas sales & distribution | 24.8% | 37.0%
Utility water distribution and wastewater treatment sales & distribution | 9.2% | 16.6%
Other revenue 1 | 1.7% | 3.4%

1 Other revenue includes gas transportation and RECs.
The purchase of electricity and natural gas by the Corporation's electric distribution and natural gas distribution system is a significant revenue driver and component of operating expenses, but these costs are effectively passed through to its customers. As a result, the Corporation uses Net Energy Sales for the Liberty Power Group (see Non-GAAP Financial Measures) and Net

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Utility Sales at the Liberty Utilities Group (see Non-GAAP Financial Measures) as a more appropriate measure of the results. Adjusting for the impact of these commodity costs, the following provides a breakdown of the Corporation’s Net Energy Sales and Net Utility Sales by percentage for the years ended December 31, 2016 and December 31, 2017:

| % Net Energy Sales/Net Utility Sales
| December 31, 2017 | December 31, 2016
Non-regulated energy sales | 17.5% | 27.6%
Utility electricity sales & distribution | 47.8% | 13.5%
Utility natural gas sales & distribution | 20.9% | 33.0%
Utility water distribution and wastewater treatment sales & distribution | 11.6% | 21.2%
Other revenue 1 | 2.2% | 4.7%

1 Other revenue includes gas transportation and RECs.
For the Liberty Power Group, the following provides a breakdown of revenue by percentage for the years ended December 31, 2016 and December 31, 2017:

| % Revenue
| December 31, 2017 | December 31, 2016
Hydroelectric generation | 19.4% | 25.0%
Wind generation | 57.2% | 48.2%
Solar generation | 4.7% | 4.9%
Thermal generation | 12.9% | 13.4%
Other revenue 1 | 5.8% | 8.5%

1 Other revenue includes RECs.
For the Liberty Utilities Group, the following provides a breakdown of revenue by percentage for the years ended December 31, 2016 and December 31, 2017:

| % Revenue
| December 31, 2017 | December 31, 2016
Utility electricity sales & distribution | 59.0% | 27.5%
Utility natural gas sales & distribution | 29.3% | 48.9%
Utility water distribution and wastewater treatment sales & distribution | 10.8% | 21.9%
Other revenue 1 | 0.9% | 1.8%

1 Other revenue includes gas transportation.

3.5 | Environmental Protection

The Corporation's businesses encompass operations which require adherence to environmental standards imposed by regulatory bodies through licenses, permits, standards, policies and legislation. Failure to operate such businesses in strict compliance with these regulatory standards may expose them to citations, claims, clean-up costs, penalties, and loss of operating licenses and permits.
The Corporation has an environmental management program including environmental policies and procedures that involve long-term environmental monitoring programs, reporting, government liaison and the development, implementation of

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emergency action plans as related to environmental matters and environmental and compliance departments with responsibility for monitoring the Corporation and its subsidiaries’ operations.
Environmental protection requirements did not have a significant financial or operational effect on the Corporation’s capital expenditures, earnings and competitive position for the twelve months ended December 31, 2017. Moreover, other regimes that provide incentives and credits for generation of renewable energy and for carbon offsets, such as those described elsewhere in this AIF, are expected to increase the earnings and benefit the competitive position of the Corporation.
The Corporation faces a number of environmental risks that are normal aspects of operating within the renewable power generation, thermal power generation and utilities business segments which have the potential to become environmental liabilities (see “Enterprise Risk Factors – Risks Relating to Operations”). Many of these risks are mitigated through the maintenance of adequate insurance which include property, boiler and machinery, environmental and excess liability policies.
3.6 Employees
The Corporation's Executive Management Group consists of eight individuals including the Chief Operating Officers of the Liberty Power Group and the Liberty Utilities Group. As at December 31, 2017, the Corporation employed a total of 2,241 people.
The Liberty Power Group employed a total of 109 employees as at December 31, 2017. All of the employees of the Liberty Power Group are non-unionized.
The Liberty Utilities Group employed a total of 1,854 employees as at December 31, 2017. The Liberty Utilities Group employees are non-unionized with the exception of: 66 employees at the CalPeco Electric System, 41 employees at the Midstates Gas System, 346 employees at The Empire District Electric Company, 183 employees at the EnergyNorth Gas System and Granite State Electric System, and 82 employees at the New England Gas System.
The corporate and shared services groups consisted, as at December 31, 2017, of an additional 194 employees located at the corporate offices in Oakville, Ontario and an additional 76 shared services employees located throughout the United States.
3.7 Foreign Operations
For the twelve months ended December 31, 2017, approximately 100% of the revenue of the Liberty Utilities Group and 70% of the revenue of the Liberty Power Group was generated from operations located in the United States.
3.8 Economic Dependence
The Corporation does not believe it is substantially dependent on any single contractual agreement or set of related agreements either for the sale of a major part of its products and services or for the purchase of a major part of its requirements for goods, services or raw materials or any franchise or license or other agreement to use a patent formula, trade secret, process or trade-name upon which its business depends.

3.9 | Social or Environmental Policies

The Corporation has formal policies and procedures that support its commitment to corporate responsibility. The Corporation’s Code of Business Conduct and Ethics is the foundation of the Corporation’s corporate responsibility framework. As a condition of employment, all employees are required to read the Code of Business Conduct and Ethics and apply the code to their work.
Employees are required to complete an annual online test which confirms their compliance with and understanding of the Code of Business Conduct and Ethics. During the course of business, any compliance exceptions are reviewed and managed promptly.
The Corporation's businesses have safety and environmental compliance policies in place. These policies have been communicated with staff, and have been incorporated into their respective Safety Mission Statements and Employee manuals.
The Corporation has an Environmental, Health and Safety Group that reports independently to the Corporation’s Vice President, People and Culture. This group is responsible for developing environmental and safety policies, developing and delivering

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environmental and safety training, conducting internal audits of environmental and safety performance, and arranging for third party environmental and safety audits.
The Corporation is actively involved in corporate responsibility. Using the Global Reporting Initiative, an international independent standards organization that helps businesses, governments and other organizations understand and communicate their impacts on issues such as climate change, human rights and corruption, the Corporation formally tracks several Global Reporting Initiative indicators. With corporate responsibility as an element of the Corporation's decision making, the Corporation reduces liability for investors, increases morale and engagement of employees, creates an environmentally cleaner community, and enhances the partnership with all of its stakeholders.
Corporate responsibility is often defined by a company’s philosophy to operate in an economically, socially and environmentally sustainable manner, while recognizing the interests of its stakeholders. The Corporation has environmentally supportive programs in place that promote energy efficiency and responsible water usage, help facilitate habitat conservation to minimize impact, monitor greenhouse gas emissions, and promote waste reduction and spill prevention. The economic branch of the Corporation's corporate responsibility efforts incorporates local spending, local hiring, and operational efficiency. The Corporation's commitment to people is demonstrated through its employee training, learning and development programs, organizational improvements, emergency management, health and safety policies, diversity in the workplace, and community involvement. The Corporation believes this philosophy will contribute to a sustainable future for its investors, communities, environment, customers, employees, governments, and business partners.

3.10 | Credit Ratings

The Corporation maintains the following credit ratings by the rating agencies 1:

| S&P |  | DBRS |  | Moody's
| 2017 | 2016 |  | 2017 | 2016 |  | 2017 | 2016
APUC - Issuer rating | BBB | BBB |  | BBB (low) | BBB(low) |  | - | -
APUC - Preferred Shares | P-3 3 | P-3 3 |  | Pfd-3 (low) | Pfd-3 (low) |  | - | -
APCo - Issuer rating | BBB | BBB |  | BBB (low) | BBB (low) |  | - | -
APCo - Senior unsecured debt | BBB | BBB |  | BBB (low) | BBB (low) |  | - | -
Liberty Utilities Co. | BBB | BBB |  | - | - |  | - | -
Liberty Utilities Finance GP1 - Issuer rating 2 | - | - |  | BBB (high) | BBB (high) |  | - | -
Liberty Utilities Finance GP1 - Senior unsecured notes | - | - |  | BBB (high) | BBB (high) |  | - | -
Empire - Issuer rating | BBB | BBB |  | - | - |  | Baa1 | Baa1
Empire - First mortgage bonds |  |  |  | - | - |  | A2 | A2
Empire - Senior unsecured debt |  |  |  | - | - |  | Baa1 | Baa1
Empire - Commercial paper |  |  |  | - | - |  | P-2 | P-2

1 | Credit ratings are intended to provide investors with an independent measure of the credit quality of an issue of securities. Credit ratings are not a recommendation to buy, sell or hold securities of APUC and do not comment as to market price or suitability for a particular investor. There can be no assurance that a rating will remain in effect for any given period of time or that the rating will not be revised or withdrawn at any time by the rating agency.
2 | Issued by Liberty Utilities Finance GP1 and guaranteed by Liberty Utilities Co.
3 | P-3 rating is equivalent to a BB rating on S&P’s global preferred share rating scale

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S&P
S&P rates debt instruments and issuers with ratings ranging from “AAA”, which represent the greatest ability of an obligor to meet its financial commitment, to “D”, which represents an obligor in payment default. A rating of “BBB” by S&P denotes an obligor having adequate capacity to meet its financial commitments. Adverse economic conditions or changing circumstances are more likely to lead to a weakened capacity of the obligor to meet its financial commitments. An S&P rating may be modified by the addition of a plus “+” or minus “-” sign to show relative standing within the major rating categories. The absence of either a plus “+” or minus “-” sign indicates that the rating is in the middle of the category.
According to the S&P rating system, preferred shares rated P-3 are regarded as having significant speculative characteristics. While such securities will likely have some quality and protective characteristics, these may be outweighed by large uncertainties or major exposures to adverse conditions. The ratings from P-1 to P-5 may be modified by “high” and “low” grades which indicate relative standing within the major rating categories.
DBRS
DBRS rates debt instruments and issuers with ratings ranging from “AAA”, which represents debt instruments and issuers of the highest credit quality, to “D”, which represent debt instruments for which a company has not made a scheduled payment of interest or principal or has made it clear it will miss such a payment in the near future. A rating of “BBB” by DBRS denotes an obligor having adequate credit quality. Protection of interest and principal is considered acceptable, but the entity is fairly susceptible to adverse changes in financial and economic conditions, or there may be other adverse conditions present which reduce the strength of the entity and its rated securities. A DBRS rating may be modified by the addition of a “(high)” or “(low)” to indicate the relative standing within a particular rating category. The absence of either a “(high)” or “(low)” designation indicates that the rating is in the middle of the category.
According to the DBRS rating system, preferred shares rated Pfd-3 are of adequate credit quality. While protection of dividends and principal is still considered acceptable, the issuing entity is more susceptible to adverse changes in financial and economic conditions, and there may be other adverse conditions present which detract from debt protection. “High” or “low” grades are used to indicate the relative standing within a rating category. The absence of either a “high” or “low” designation indicates the rating is in the middle of the category.
Moody's
Moody's rates debt instruments and issuers with ratings ranging from “Aaa”, which represent the greatest ability of an obligor to meet its financial commitment, to “C”, which represents an obligor in payment default. A rating of “A” by Moody's denotes obligations judged to be upper-medium grade and are subject to low credit risk, while a rating of “Baa” by Moody's denotes an obligations judged to be medium-grade and subject to moderate credit risk and as such may possess certain speculative characteristics. A Moody's rating may be modified by the addition of a numerical modifiers 1, 2, and 3 to show relative standing within the major rating categories.
Short-term obligations of an issuer may carry a rating ranging from Prime-1 or “P-1”, which represents an issuer's superior ability to repay short-term debt obligations, to “P-3”, which represent an issuer's acceptable ability to repay short-term obligations.
4. ENTERPRISE RISK FACTORS
The Corporation is subject to a number of risks and uncertainties. A risk is the possibility that an event might happen in the future that could have a negative effect on the financial condition, financial performance or business of the Corporation. The actual effect of any event on the Corporation’s business could be materially different from what is anticipated. The description of risks below does not include all possible risks.
An enterprise risk management, or 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 the Corporation’s current objectives, as well as those inherent to strategic alternatives available to the

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Corporation. The Corporation’s ERM policy details the risk management processes, risk appetite, and risk governance structure which clearly establishes accountabilities for managing risk across the organization.
As part of the risk management processes, risk registers have been developed across the organization through ongoing risk identification and risk assessment exercises facilitated by the Corporation’s internal ERM team. Risk information is sourced throughout the organization using a variety of methods including risk identification interviews and workshops, as well as the Corporation's “Risk Insights” program, which provides all employees with a mechanism to communicate risks and opportunities at any time. Key risks and associated mitigation strategies are reviewed by the executive-level Enterprise Risk Management Council and are presented to the Board’s Risk Committee on a quarterly basis.
Risks are evaluated consistently across the organization using a common risk scoring matrix to assess impact and likelihood. Financial, reputational, and safety implications are among those considered when determining the impact of a potential risk. Risk treatment priorities are established based upon these risk assessments and incorporated into the development of the Corporation’s strategic and business plans.
The development and execution of risk treatment plans for the organization’s top risks are actively monitored by the Executive team. The Corporation’s internal audit team is responsible for conducting audits to validate and test the effectiveness of controls for key risks. Audit findings are discussed with business owners and reported to the Audit Committee on a quarterly basis. All material changes to exposures, controls or treatment plans of key risks are reported to the ERM team, Enterprise Risk Management Council, the Corporate Governance and Risk Committees, and the Board for consideration.
The Corporation’s ERM framework follows the guidance of ISO 31000:2009. The Board oversees management to ensure the risk governance structure and risk management processes are robust, and that the Corporation’s risk appetite is thoroughly considered in decision-making across the organization.
4.1 Risk Factors Relating to Operations
The Corporation’s operations involve numerous risks that could disrupt or adversely affect its business, results of operations, financial position and cash flows.
The operation of the Corporation’s power generation facilities, utility systems and other assets involve a variety of risks customary to the power and utilities sector, including:

• | severe weather conditions and natural disasters;

• | global climate change;

• | environmental contamination/wildlife impacts;

• | casualty events such as fires, explosions, security breaches or other occurrences;

• | commodity supply and transmission constraints or interruptions;

• | workplace and public safety events;

• | loss of key personnel;

• | labour disputes;

• | poor employee performance/workforce effectiveness;

• | demand (including seasonality);

• | loss of key customers;

• | reduction in the price received for goods/services;

• | reliance on transmission systems and facilities operated by third parties;

• | land use rights/access;

• | critical equipment breakdown or failure;

• | lower-than-expected levels of efficiency or operational performance;

• | wars and terrorist acts;

• | commodity price;

• | obligations to serve; and

• | the Corporation’s reliance on subsidiaries.

These and other operating events and conditions could result in service disruptions and may reduce the Corporation’s revenues, increase costs, or both, and may materially affect its business, results of operations, financial position, valuation and cash

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flows, particularly if a situation is not resolved in a timely manner or the financial impacts of restoration are not alleviated through insurance policies or regulated rate recovery.
The Corporation’s generation, distribution and transmission utility assets may be negatively impacted by changes in general economic, credit, social and market conditions.
The Corporation’s generation, distribution and transmission utility assets are affected by energy demand in the jurisdictions in which they operate, that may change as a result of fluctuations in general economic conditions, energy prices, employment levels, personal disposable income and housing starts. Significantly reduced energy demand in the Corporation’s service territories could reduce capital spending forecasts, and specifically capital spending related to new customer growth. A reduction in capital spending would, in turn, affect the Corporation’s rate base and earnings growth. A severe prolonged downturn in economic conditions may have an adverse effect on the Corporation’s results of operations, financial condition and cash flows despite regulatory measures, where applicable, available to compensate for reduced demand. In addition, an extended decline in economic conditions could make it more difficult for customers to pay for the utility services they consume, thereby affecting the aging and collection of the utilities’ trade receivables.
Energy conservation, energy efficiency, distributed generation and other factors that reduce energy demand could adversely affect the Corporation’s business, financial condition and results of operations.
The emergence of initiatives designed to reduce greenhouse gas emissions and control or limit the effects of global warming and overall climate change has increased the incentive to increase energy efficiency and reduce energy consumption. In addition, significant technological advancements are taking place in the electric industry, including advancements related to self-generation and distributed energy technologies such as fuel cells, micro turbines, wind turbines and solar cells. Adoption of these technologies may increase as a result of government subsidies, improving economics and changing customer preferences.
Increased adoption of these practices, requirements and technologies could reduce demand for utility-scale electricity generation, which may adversely affect market prices at which the Liberty Power Group can sell wholesale electric power.
Increased adoption of these practices may decrease the pool of customers from whom fixed costs would be recovered. If the Liberty Utilities Group were unable to adjust distribution rates to reflect the reduced energy demand, the Corporation’s business, financial condition and results of operations could be adversely affected.
The Corporation is subject to physical and financial risks associated with global climate change.
Global climate change creates physical and financial risk. Physical risks from climate change may include an increase in sea level and changes in weather conditions, such as changes in precipitation and extreme weather events. Customers’ energy needs vary with weather conditions, primarily temperature and humidity. For residential customers, heating and cooling represent their largest energy use. To the extent weather conditions are affected by climate change, customers’ energy use could increase or decrease depending on the duration and magnitude of the changes, which could adversely affect the Corporation’s business, results of operations and cash flows.
The Corporation and its subsidiaries face a number of environmental risks which have the potential to result in significant environmental liabilities.
The Corporation and its subsidiaries face a number of environmental risks that are normal aspects of operating within the power generation and utilities business segments, which have the potential to result in harm to the environment, including wildlife, resulting in significant environmental liabilities and reputational impact. Certain environmental risks associated with the Corporation’s operations include uncontrolled natural gas or contaminant releases (or releases above the permitted limits), generation of hazardous materials, failure to maintain compliance with obligations under permits and licenses (such as continuous emissions monitoring, periodic reporting/source testing, and general performance/operating conditions), operations adjustments or liability, and related financial impacts, resulting from wildlife mortality monitoring, emissions including noise and dam safety.
In addition, like other industrial companies, the Corporation’s operating subsidiaries generate certain hazardous wastes, which must be managed in accordance with various federal, state and local environmental laws. Under federal and state laws,

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potential liability for historic contamination of property may be imposed on responsible parties jointly and severally, without fault, even if the activities were lawful when they occurred.
The Corporation’s facilities and operations are exposed to effects of natural disasters and other catastrophic events beyond the Corporation’s control and such events could result in a material adverse effect.
The Corporation’s facilities and operations are exposed to potential interruption and damage, and partial or full loss, resulting from environmental disasters (e.g. floods, high winds, fires, ice storms, and earthquakes), other seismic activity, equipment failures and the like. There can be no assurance that in the event of an earthquake, hurricane, tornado, tsunami, typhoon, terrorist attack, act of war or other natural, manmade or technical catastrophe, all or some parts of the Corporation’s generation facilities and infrastructure systems will not be disrupted. The occurrence of a significant event which disrupts the ability of the Corporation’s power generation assets to produce or sell power for an extended period, including events which preclude existing customers under power purchase agreements from purchasing electricity, could have a material negative impact on the Corporation’s business. The Corporation’s infrastructure could be exposed to effects of severe weather conditions, natural and man-made disasters and potentially other catastrophic events. The occurrence of such an event may not release the Corporation from performing its obligations pursuant to power purchase agreements or other agreements with third parties.
Certain of the Corporation’s utilities operate in remote and mountainous terrain with a risk of loss or damage from forest fires, floods, washouts, landslides, earthquakes, avalanches and other acts of nature.
Security breaches, criminal activity, terrorist attacks and other disruptions to the Corporation’s information technology infrastructure could directly or indirectly interfere with the Corporation’s operations, could expose the Corporation or its customers or employees to risk of loss, and could expose the Corporation to liability, regulatory penalties, reputational damage and other harm to its business.
The Corporation relies upon information technology networks and systems to process, transmit and store electronic information, and to manage and support a variety of business processes and activities. The Corporation also uses information technology systems to record, process and summarize financial information and results of operations for internal reporting purposes and to comply with financial reporting, legal and tax requirements. The Corporation’s technology networks and systems collect and store sensitive data, including system operating information, proprietary business information belonging to the Corporation and third parties, as well as personal information belonging to the Corporation’s customers and employees.
The Corporation’s information technology networks and infrastructure may be vulnerable to damage, disruptions or shutdowns due to attacks by hackers or breaches due to employee error or malfeasance, disruptions during software or hardware upgrades, telecommunication failures, natural disasters or other catastrophic events. The occurrence of any of these events could impact the reliability of the Corporation’s power generation facilities and utility distribution systems; could expose the Corporation, its customers or its employees to a risk of loss or misuse of information; and could result in legal claims or proceedings, liability or regulatory penalties against the Corporation, damage the Corporation’s reputation or otherwise harm the Corporation’s business. The Corporation cannot accurately assess the probability that a security breach may occur or accurately quantify the potential impact of such an event. The Corporation can provide no assurance that it will identify and remedy all security or system vulnerabilities or that unauthorized access or errors will be identified and remedied.
The loss of key personnel, the inability to hire and retain qualified employees, and labour disruptions could adversely affect the Corporation’s business, financial position and results of operations.
The Corporation’s operations depend on the continued efforts of its employees. Retaining key employees and maintaining the ability to attract new employees are important to the Corporation’s operational and financial performance. The Corporation cannot guarantee that any member of its management or any one of its key employees will continue to serve in any capacity for any particular period of time.
Certain events or conditions, such as an aging workforce, epidemic or pandemic, mismatch of skill set or complement to future needs, or unavailability of contract resources may lead to operating challenges and increased costs. The challenges the Corporation might face as a result of such risks include a lack of resources, losses to its knowledge base and the time required to develop new workers’ skills. In any such case, costs, including costs for contractors to replace employees, productivity costs and safety costs may rise. If the Corporation is unable to successfully attract and retain an appropriately qualified workforce, its financial position or results of operations could be negatively affected.

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The maintenance of a productive and efficient labour environment without disruptions cannot be assured. In the event of a strike, work stoppage or other form of labour disruption, the Corporation would be responsible for procuring replacement labour and could experience disruptions in its operations and incur additional expense.
The Corporation’s revenues and results of operations are affected by seasonal fluctuations and year to year variability in weather conditions and natural resource availability.
The Corporation is subject to risks associated with seasonal fluctuations and year to year variability in weather conditions and natural resource availability, which affect the quantity of electric power generated and sold by the Liberty Power Group, the availability of water to be distributed by the Liberty Utilities Group and the demand for the utility services of the Liberty Utilities Group.
Demand for energy sold to retail customers in the maritime region is primarily affected by temperature. Demand for energy during colder months is generally greater than warmer months as the load served is located in a “winter peaking” region.
The Liberty Utilities Group’s water distribution operations depend on an adequate supply of water to meet present and future demands of customers. Drought conditions could interfere with sources of water supply used by the utilities and affect their ability to supply water in sufficient quantities to existing and future customers. An interruption in the water supply could have an adverse effect on the results of operations of these utilities.
Demand for water, electricity and natural gas from the Liberty Utilities Group’s utility distribution systems is affected by weather conditions and temperature. Demand for water may decrease if there is above normal rainfall or rainfall is more frequent than normal, or if government restrictions are imposed on water usage during drought conditions. Demand for electricity and natural gas are also subject to significant seasonal variation, year-to-year variations and changes in weather patterns.
Please see “Description of the Business – Liberty Power Group – Cycles and Seasonality” and “Description of the Business – Liberty Utilities Group – Cycles and Seasonality” for a detailed description and discussion of this risk.
The Corporation historically has, and may in the future, enter into long-term power purchase contracts and derivative contracts to reduce the risk of fluctuations in electricity prices, which contracts could give rise to performance and financial risks and could result in significant costs to the Corporation.
The Liberty Power Group sells a significant portion of the energy (and renewable energy credits) it generates under long-term power purchase agreements. To the extent a generating asset is not fully covered by a power purchase contract, the Liberty Power Group may enter into financial or physical power hedges to reduce the risk from fluctuations in market price. For instance, several of the Liberty Power Group’s wind energy production facilities are subject to long-term energy price hedges for a portion of their expected energy production. The Corporation may incur significant costs in establishing or terminating hedging arrangements or may be unable to benefit from favorable changes in market price as a result of these hedges.
In addition, the Corporation may not be able to generate power in the amounts or at the times required by the applicable hedge contract, due to the variable nature of the natural resource (for renewable power generation) or due to transmission grid curtailments, mechanical failures or other reasons. Because of this risk, the Corporation typically does not hedge the full expected production of a particular facility, which leaves a portion of expected production subject to market price risk. In addition, production shortfalls force the Liberty Power Group to purchase power in the merchant market at prevailing rates to settle against the applicable hedge contract. Such factors could materially and adversely affect the Corporation’s results of operations and cash flows, depending on both the amount of shortfall and the market price of electricity at the time of the shortfall.
Changes in technology and regulatory policies may lower the value of electric utility facilities.
The Corporation primarily generates electricity at large central facilities and delivers that electricity to customers using its transmission and distribution facilities. This method results in economies of scale and generally lower costs than newer technologies, such as fuel cells and microturbines, and distributed generation using either new or existing technology. Other technologies, such as light emitting diodes (LEDs), increase the efficiency of electricity and, as a result, lower the demand for it. Changes in regulatory policies and advances in batteries or energy storage, wind turbines and photovoltaic solar cells are reducing costs of new technology to levels that are making them competitive with some central station electricity production and delivery. The ability to maintain relatively low-cost, efficient and reliable operations, to establish fair regulatory mechanisms

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and to provide cost-effective programs and services to customers are significant determinants of the Corporation’s competitiveness. Further, in the event that alternative generation resources are mandated, subsidized or encouraged through climate legislation or regulation or otherwise are economically competitive and added to the available generation supply, such resources could displace a higher marginal cost central generating plant, which could reduce the price at which market participants sell their electricity. This occurrence could then reduce the market price at which all generators in that region would be able to sell their output and could adversely affect the Corporation’s financial condition, results of operations and cash flows, which could also result in an impairment of certain long-lived assets.
Liberty Power Group’s facilities rely on national and regional transmission systems and related facilities that are owned and operated by third parties and have both regulatory and physical constraints that could impede access to electricity markets.
A substantial portion of the Liberty Power Group’s power generation facilities depend on electric transmission systems and related facilities owned and operated by third parties to deliver the electricity the Liberty Power Group generates to delivery points where ownership changes and the Corporation is paid. These grids operate with both regulatory and physical constraints which in certain circumstances may impede access to electricity markets. There may be instances in system emergencies in which the Liberty Power Group’s power generation facilities are physically disconnected from the power grid, or their production curtailed, for short periods of time. Most of the Corporation’s electricity sales contracts do not provide for payments to be made if electricity is not delivered.
The power generation facilities of the Liberty Power Group may also be subject to changes in regulations governing the cost and characteristics of use of the transmission and distribution systems to which its power generation facilities are connected. In the future, these power generation facilities may not be able to secure access to interconnection or transmission capacity at reasonable prices, in a timely fashion or at all, which could then cause delays and additional costs in attempting to negotiate or renegotiate power purchase agreements or to construct new projects. Any such increased costs and delays could delay the commercial operation dates of Liberty Power Group’s new projects and negatively impact the Corporation’s revenues and financial condition.
The Corporation’s subsidiaries do not own all of the land on which their projects are located and their use and enjoyment of real property rights for their projects may be adversely affected by the rights of lienholders and leaseholders that are superior to those of the grantors of those real property rights to the Corporation’s subsidiaries’ projects, which could have a material adverse effect on their business, results of operations, financial condition and cash flows.
The Corporation’s subsidiaries do not own all of the land on which their projects are located. Such projects generally are, and future projects may be, located on land occupied under long-term easements, leases and rights of way. The ownership interests in the land subject to these easements, leases and rights of way may be subject to mortgages securing loans or other liens and other easements, lease rights and rights of way of third parties that were created previously. As a result, some of the rights under such easements, leases or rights of way held by the Corporation’s operating subsidiaries may be subject to the rights of these third parties, and the rights of the Corporation’s operating subsidiaries to use the land on which their projects are or will be located and their projects’ rights to such easements, leases and rights of way could be lost or curtailed. Any such loss or curtailment of the rights of the Corporation’s operating subsidiaries to use the land on which their projects are or will be located could have a material adverse effect on their business, results of operations, financial condition and cash flows.
The Corporation may experience critical equipment breakdown or failure, which could have a material adverse effect on the Corporation’s financial condition, results of operations, liquidity, reputation and ability to make distributions.
The Corporation’s facilities are subject to the risk of critical equipment breakdown or failure and lower-than-expected levels of efficiency or operational performance due to the deterioration of assets from use or age, latent defect and design or operator error, among other things. These and other operating events and conditions could result in service disruptions and, to the extent that a facility’s equipment requires longer than forecasted down times for maintenance and repair, or suffers disruptions of power generation, distribution or transmission for other reasons, the Corporation’s business, operating results, financial condition or prospects could be adversely affected. In addition, a portion of the Corporation’s infrastructure is located in remote areas, which may make access to perform maintenance and repairs difficult if such assets become damaged.

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Terrorist attacks, and the threat of terrorist attacks, have resulted in increased costs to the business of the Corporation. Continued hostilities or sustained military campaigns may adversely impact our consolidated financial position, results of operations and cash flows.
The long-term impact of terrorist attacks and the magnitude of the threat of future terrorist attacks on the electric utility and natural gas midstream industry in general, and on the Corporation in particular, cannot be known. Increased security measures taken by the Corporation as a precaution against possible terrorist attacks have resulted in increased costs to the business of the Corporation. Uncertainty surrounding continued hostilities or sustained military campaigns may affect operations of the Corporation in unpredictable ways, including disruptions of supplies and markets for products of the Corporation, and the possibility that our infrastructure facilities could be direct targets of, or indirect casualties of, an act of terror. The Corporation cannot predict the impact that a terrorist attack may have on the energy industry in general. The Corporation’s facilities could be direct targets or indirect casualties of such attacks. The effects of such attacks could include disruption to the Corporation’s generation, transmission and distribution systems or to the electrical grid in general, and could result in a decline in the general economy and have a material adverse effect on the Corporation.
The Corporation’s financial performance may be adversely affected by fluctuations in commodity prices.
Market prices for power, generation capacity, ancillary services and natural gas are unpredictable and tend to fluctuate substantially, which may affect the Corporation’s operating results. With respect to the Liberty Utilities Group, commodity price exposure is primarily limited to the cost of electricity and natural gas. Although the Liberty Utilities Group’s utility rates and tariffs are generally designed to allow recovery of commodity costs, timing differences and other factors, which may be exacerbated by fluctuating prices, may result in less than full recovery.
Cash flow deferrals related to energy commodities can be significant.
The Corporation is permitted to collect from customers only amounts approved by regulatory commissions. However, the Corporation’s costs to provide energy service can be much higher or lower than the amounts currently billed to customers. The Corporation is permitted to defer income statement recognition and recovery from customers for some of these differences, which are recorded as deferred charges with the opportunity for future recovery through retail rates. These deferred costs are subject to review for prudence and potential disallowance by regulators, who have discretion as to the extent and timing of future recovery or refund to customers.
Power and natural gas costs higher than those recovered in retail rates reduce cash flows. Amounts that are not allowed for deferral or which are not approved to become part of customer rates affect the Corporation’s results of operations.
Even if the regulators ultimately allow the Corporation to recover deferred power and natural gas costs, the Corporation’s operating cash flows can be negatively affected until these costs are recovered from customers.
The Liberty Utilities Group is obligated to serve utility customers within its certificated service territories, which may require that the Corporation make capital expenditures and incur indebtedness to expand service to new customers.
The Liberty Utilities Group may have facilities located within areas of the United States experiencing growth. These utilities may have an obligation to service new residential, commercial and industrial customers. While expansion to serve new customers will likely result in increased future cash flows, it may require significant capital commitments in the immediate term. Accordingly, the Liberty Utilities Group may be required to solicit additional capital or incur additional borrowings to finance these future construction obligations.
As a holding company, the Corporation does not have its own operating income and must rely on the cash flows from its subsidiaries to pay dividends and make debt payments.
The Corporation is a holding company with no significant operations of its own, and the Corporation’s primary assets are shares or other ownership interests of its subsidiaries. The Corporation’s subsidiaries are separate and distinct legal entities and may have no obligation to pay any amounts to the Corporation, whether through dividends, loans or other means. The ability of the Corporation’s subsidiaries to pay dividends or make distributions to the Corporation depends on several factors, including each subsidiary’s actual and projected earnings and cash flow, capital requirements and general financial condition, regulatory restrictions, covenants contained in credit facilities to which they are parties, and the prior rights of holders of their existing and future secured debt and other debt or equity securities. Further, the amount and payment of dividends from any subsidiary

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is at the discretion of such subsidiary’s board of directors, which may reduce or cease payment of dividends at any time. In addition, there may be changes to tax regulation affecting the repatriation of dividends from other countries, which may negatively affect us.
The Corporation and its subsidiaries are not able to insure against all potential risks and may become subject to higher insurance premiums, and the Corporation’s ability to obtain insurance and the terms of any available insurance coverage could be materially adversely affected by international, national, state or local events and company-specific events, as well as the financial condition of insurers.
The Corporation maintains insurance coverage for certain exposures, but this coverage is limited and the Corporation is generally not fully insured against all significant losses. Such insurance may not continue to be offered on an economically feasible basis and may not cover all events that could give rise to a loss or claim involving the Corporation’s assets or operations. The Corporation’s ability to obtain and maintain insurance and the terms of any available insurance coverage could be materially adversely affected by international, national, state or local events and company-specific events, as well as the financial condition of insurers.
If the Corporation were to incur a serious uninsured loss or a loss significantly exceeding the limits of their insurance policies, the results could have a material adverse effect on the Corporation’s business, results of operations, financial condition and cash flows. In the event of a large uninsured loss caused by severe weather conditions, natural disasters and certain other events beyond the control of the Liberty Utilities Group, the Corporation may make an application to an applicable regulatory authority for the recovery of these costs through customer rates to offset any loss. However, the Corporation cannot provide assurance that the regulatory authorities would approve any such application in whole or in part. This potential recovery mechanism is not available to Liberty Power Group.
4.2 Risk Factors Relating to Financing and Financial Reporting
A downgrade in the Corporation’s credit rating or the credit ratings of its subsidiaries could have a material adverse effect on the Corporation’s business, cost of capital, financial condition and results of operations.
The Corporation has a long term consolidated corporate credit rating of BBB (flat) from S&P and a BBB (low) rating from DBRS. Liberty Utilities Finance GP1, a special purpose financing affiliate of Liberty Utilities Co., has a BBB (high) issuer rating from DBRS. The ratings indicate the agencies’ assessment of the ability to pay the interest and principal of debt securities issued by such entities. The lower the rating, the higher the interest cost of the securities when they are sold. See “Description of the Business – Credit Ratings”.
There can be no assurance that any of the Corporation’s current ratings will remain in effect for any given period of time or that a rating will not be lowered or withdrawn entirely by a rating agency if, in its judgment, circumstances in the future so warrant. A downgrade in the Corporation’s or Liberty Utilities Finance GP1’s credit ratings would result in an increase in the Corporation’s borrowing costs under its bank credit facilities and future issuances of long term debt securities. If any of these ratings fall below investment grade (investment grade is defined as BBB- or above for S&P and BBB low or above for DBRS), the Corporation’s ability to issue short-term debt or other securities, or to market those securities, would be impaired or become more difficult or expensive. Therefore, any such downgrades could have a material adverse effect on the Corporation’s business, cost of capital, financial condition and results of operations.
Financial market disruptions or other factors could increase financing costs or limit access to credit and capital markets, which could adversely affect the Corporation’s ability to refinance existing indebtedness on favorable terms, execute its acquisition and investment strategy, and finance its other activities upon favorable terms.
As of December 31, 2017, the Corporation had substantial indebtedness. Management of the Corporation believes, based on its current expectations as to the Corporation’s future performance, that the cash flow from operations, funds available under its revolving credit facilities and its ability to access capital markets will be adequate to enable the Corporation to finance its operations, execute its business strategy and maintain an adequate level of liquidity for at least the next twelve months. However, the Corporation’s expected revenue and capital expenditures are only estimates. Moreover, actual cash flows from operations will depend on regulatory, market and other conditions that are beyond the Corporation’s control. As a result, there can be no assurance that management’s expectations as to future performance will be realized.

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The Corporation’s ability to raise additional debt or equity, on favorable terms or at all, may be adversely affected by any adverse financial and operational performance or by financial market disruptions or other factors outside the Corporation’s control.
In addition, the Corporation may at times incur indebtedness in excess of its long-term leverage targets, in advance of raising the additional equity necessary to repay such indebtedness and maintain its long-term leverage target. Any increase in the Corporation’s leverage could, among other things, limit the Corporation’s ability to obtain additional financing for working capital, investment in subsidiaries, capital expenditures, debt service requirements, acquisitions and general corporate or other purposes; restrict the Corporation’s flexibility and discretion to operate its business; limit the Corporation’s ability to declare dividends; require the Corporation to dedicate a portion of cash flows from operations to the payment of interest on its existing indebtedness, in which case such cash flows will not be available for other purposes; cause ratings agencies to re-evaluate or downgrade the Corporation’s existing credit ratings; expose the Corporation to increased interest expense on borrowings at variable rates; limit the Corporation’s ability to adjust to changing market conditions; place the Corporation at a competitive disadvantage compared to its competitors that have less debt; make the Corporation vulnerable to any downturn in general economic conditions; and render the Corporation unable to make expenditures that are important to its future growth strategies.
The Corporation will need to refinance its existing consolidated indebtedness over time. There can be no assurance that the Corporation will be successful in refinancing its indebtedness when necessary or that additional financing will be obtained when needed, on commercially reasonable terms or at all. In the event that the Corporation cannot refinance indebtedness or raise additional indebtedness, or if the Corporation cannot refinance its indebtedness or raise additional indebtedness on terms that are not less favourable than the current terms, the Corporation’s cash flows and ability to declare dividends may be adversely affected.
The Corporation’s ability to meet its debt service requirements will depend on its ability to generate cash in the future, which depends on many factors, including the Corporation’s financial performance, debt service obligations, the realization of the anticipated benefits of acquisition and investment activities, and working capital and capital expenditure requirements. In addition, the Corporation’s ability to borrow funds in the future to make payments on outstanding debt will depend on the satisfaction of covenants in existing credit agreements and other agreements. A failure to comply with any covenants or obligations under the Corporation’s consolidated indebtedness could result in a default under one or more such instruments, which, if not cured or waived, could result in the termination of dividends by the Corporation and permit acceleration of the relevant indebtedness. There can be no assurance that, if such indebtedness were to be accelerated, the Corporation’s assets would be sufficient to repay such indebtedness in full. There can also be no assurance that the Corporation will generate cash flow in amounts sufficient to pay its outstanding indebtedness or to fund the Corporation’s other liquidity needs.
Sustained increases in interest rates could negatively affect the Corporation’s financing costs, ability to access capital and ability to continue successfully implementing its business strategy.
The Corporation is exposed to interest rate risk from certain outstanding variable interest indebtedness. As a result, increases in interest rates could materially increase the Corporation’s financing costs and adversely affect its results of operations, cash flows, borrowing capacity and ability to implement its business strategy.
Currency exchange rate fluctuations may affect the Corporation’s financial results and increase certain financing risks.
Currency fluctuations may affect the cash flows the Corporation realizes from its consolidated operations because a significant portion of the Corporation’s revenues are generated in U.S. dollars. Although the Corporation may enter into derivative contracts to hedge currency exchange rate exposure, the Corporation typically does not hedge its full exposure. If the Corporation does enter into currency hedges and exchange rates move in a favourable direction, such currency hedges may reduce or eliminate the Corporation’s realization of the benefit of favorable exchange rate movement. In addition, any currency hedging transactions will be subject to risks that the applicable counterparty may prove unable or unwilling to perform their obligations under the contracts, as a result of which the Corporation would lose some or all of the anticipated benefits of such hedging transactions.

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The Corporation’s existing credit facilities contain, and agreements that the Corporation may enter into in the future may contain, covenants that could restrict its financial flexibility.
The Corporation’s existing credit facilities, and the credit facilities of its subsidiaries, contain covenants imposing certain requirements on the Corporation’s business including covenants regarding the ratio of indebtedness to total capitalization. Furthermore, the Corporation’s subsidiaries periodically issue long-term debt, historically consisting of both secured and unsecured indebtedness. These third-party debt agreements also contain covenants, including covenants regarding the ratio of indebtedness to total capitalization. These requirements may limit the Corporation’s ability to take advantage of potential business opportunities as they arise and may adversely affect the Corporation’s conduct and the current business of its operating subsidiaries, including restricting the ability to finance future operations and capital needs and limiting the subsidiaries’ ability to engage in other business activities. Other covenants place or could place restrictions on the Corporation’s ability and the ability of its operating subsidiaries to, among other things, incur additional debt, create liens, and sell or transfer assets.
Agreements the Corporation enters into in the future may also have similar or more restrictive covenants, especially if the general credit market deteriorates. A breach of any covenant in the existing credit facilities or the agreements governing the Corporation’s other indebtedness would result in an event of default. Certain events of default may trigger automatic acceleration of payment of the underlying obligations or may trigger acceleration of payment if not remedied within a specified period. Events of default under one agreement may trigger events of default under other agreements, although the Corporation’s regulated utilities are not subject to the risk of default of affiliates. Should payments become accelerated as the result of an event of default, the principal and interest on such borrowing would become due and payable immediately. If that should occur, the Corporation may not be able to make all of the required payments or borrow sufficient funds to refinance the accelerated debt obligations. Even if new financing is then available, it may not be on terms that are acceptable to the Corporation.
A significant portion of the Corporation’s debt will mature over the next five years and will need to be paid or refinanced, and changes to the debt and equity markets could adversely affect the Corporation’s business.
A significant portion of the Corporation’s debt is set to mature in the next five years, including its revolving credit facility. The Corporation may not be able to refinance its maturing debt on commercially reasonable terms, or at all, depending on numerous factors, including its financial condition and prospects at the time and the then current state of the banking and capital markets in Canada and the United States.
Challenges to the Corporation’s tax positions, and changes in applicable tax laws, could materially and adversely affect the return to the Corporation’s shareholders.
The Corporation is subject to income and other taxes primarily in the United States and Canada. Changes in tax laws or interpretations thereof in the jurisdictions in which we do business could adversely affect the Corporation’s results from operations, return to shareholders and cash flow.
The Corporation cannot provide assurance that the Canada Revenue Agency, the Internal Revenue Service or any other applicable taxation authority will agree with the tax positions taken by the Corporation, including with respect to claimed expenses and the cost amount of the Corporation’s depreciable properties. A successful challenge by an applicable taxation authority regarding such tax positions could adversely affect our results of operations and financial position.
Development by the Liberty Power Group of renewable power generation facilities in the United States depends in part on federal tax credits and other tax incentives. Although these incentives have been extended on multiple occasions, the most recent extension provides for a multi-year step-down. While recently enacted U.S. tax reform legislation did not make any changes to the multi-year step-down, there can be no assurance that there will not be further changes in the future. If these incentives are reduced or we are unable to complete construction on anticipated schedules, the reduced incentives may be insufficient to support continued development and construction of renewable power facilities in the United States or may result in substantially reduced benefits from facilities that we are committed to complete. In addition, the Liberty Power Group has entered into certain tax equity financing transactions with financial partners for certain of its renewable power facilities in the United States, under which allocations of future cash flows to the Corporation from the applicable facility could be adversely affected in the event that there are changes in U.S. tax laws that apply to facilities previously placed in service.

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The Corporation is subject to funding risks associated with defined benefit pension and OPEB plans.
Certain utility businesses acquired by the Corporation maintain defined benefit pension plans covering substantially all of the employees of the acquired business, and other post-employment benefit (“OPEB”) plans for eligible retired employees, including retiree health care and life insurance benefits. The Corporation also provides a defined benefit cash balance pension plan covering substantially all its new employees and current employees at its water utilities, under which employees are credited with a percentage of base pay plus a prescribed interest rate credit.
Future contributions to the Corporation’s plans are impacted by a number of variables, including the investment performance of the plans’ assets and the discount rate used to value the liabilities of the plans. If capital market returns are below assumed levels, or if discount rates decrease, the Corporation could be required to make contributions to its plans in excess of those currently expected, which would adversely affect the Corporation’s cash flows.
The Corporation is subject to credit risk of customers and other counterparties.
The Corporation is subject to credit risk with respect to the ability of customers and other counterparties to perform their obligations to the Corporation, including paying amounts that they owe to the Corporation. This credit risk exists with respect to utility customers, as well as counterparties to long term power purchase contracts, supply agreements and derivative financial instruments.
Adverse conditions in the energy industry or in the general economy, as well as circumstances of individual customers or counterparties, may adversely affect the ability of a customer or counterparty to perform as required under its contract with the Corporation. Losses from a utility customer may not be offset by bad debt reserves approved by the applicable utility regulator. If a customer under a long-term power purchase agreement is unable to perform, the Liberty Power Group may be unable to replace the contract on comparable terms, in which case sales of power (and, if applicable, renewable energy credits and ancillary services) from the facility would be subject to market price risk and may require refinancing of indebtedness related to the facility or otherwise have a material adverse effect. Default by other counterparties, including counterparties to hedging contracts that are in an asset position and to short-term investments, also could adversely affect the financial results of the Corporation.
The Corporation makes certain assumptions, judgments and estimates that affect amounts reported in its consolidated financial statements with respect to potential asset retirement obligations, which, if not accurate, may adversely affect its financial results.
The Corporation and its subsidiaries conduct periodic reviews of potential asset retirement obligations that may require recognition in the Corporation’s financial statements. As part of this process, the Corporation and its subsidiaries consider requirements outlined in applicable operating permits, leases and other agreements, the probability of related agreements being extended, the ability to quantify such expense, the timing of incurring the potential expenses, as well as other factors in evaluating if such obligations exist and in estimating the fair value of such obligations. Inaccuracies in these estimates could result in the Corporation incurring significant expenses related to retirement obligations and adversely affect the Corporation’s financial results.
The Corporation’s asset retirement obligations mainly relate to legal requirements for: (i) removal of wind, solar and thermal facilities upon termination of land leases; (ii) cutting (disconnecting from the distribution system), purging (cleaning of natural gas and PCB contaminants) and capping gas mains within the gas distribution and transmission system when mains are retired in place, or disposing of sections of gas main when removed from the pipeline system; (iii) cleaning and removing storage tanks containing waste oil and other waste contaminants; and (iv) removing asbestos upon major renovation or demolition of structures and facilities.
4.3 Risk Factors Relating to Regulatory Environment
The profitability of the Corporation’s businesses depends in part on regulatory climates in the jurisdictions in which it operates, and the failure to maintain required regulatory authorizations would materially and adversely affect the Corporation.
The utility commissions in the states in which the Liberty Utilities Group operates regulate many aspects of its utility operations, including the rates that the Liberty Utilities Group can charge customers, siting and construction of facilities, pipeline safety and compliance, customer service and the utility’s ability to recover the costs that it incurs, including capital expenditures and fuel and purchased power costs. In addition, the electrical transmission system owned by the Liberty Power Group, which

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is used to connect the Tinker Hydro Facility to the New Brunswick transmission network, is also subject to regulation by the New Brunswick Energy and Utilities Board.
A fundamental risk faced by any regulated utility is the disallowance by the utility’s regulator of costs requested to be placed into the utility’s revenue requirement. In addition, the time between the incurrence of costs and the granting of the rates to recover those costs by state or provincial regulatory agencies – known as “regulatory lag” – can adversely affect profitability. If the Corporation is unable to recover increased costs of operations or its investments in new facilities, or in the event of significant regulatory lag, the Corporation’s results of operations could be adversely affected.
In addition, there is a risk that the utility’s regulator will not approve the transmission and distribution revenue requirements requested in outstanding or future applications for rates or will, on its own initiative, seek to reduce the existing revenue requirements. Rate applications for revenue requirements are subject to the utility regulator’s review process, usually involving participation from intervenors and a public hearing process. There can be no assurance that resulting decisions or rate orders issued by the utility regulators will permit the Corporation to recover all costs actually incurred, costs of debt and income taxes, or to earn a particular return on equity. A failure to obtain acceptable rate orders, or approvals of appropriate returns on equity and costs actually incurred, may materially adversely affect: Liberty Utilities Group’s transmission or distribution businesses, the undertaking or timing of capital expenditures, ratings assigned by credit rating agencies, the cost and issuance of long-term debt, and other matters, any of which may in turn have a material adverse effect on the Corporation. In addition, there is no assurance that the Corporation will receive regulatory decisions in a timely manner and, therefore, costs may be incurred prior to having an approved revenue requirement.
In the case of some of the Corporation’s hydroelectric generating facilities, water rights are owned by governments that reserve the right to control water levels, which may affect revenue, while in the United States, hydroelectric generating facilities are required to be licensed or have valid exemptions from FERC. The failure to obtain all necessary licenses or permits for such facilities, including renewals thereof or modifications thereto, may result in an inability to operate the facility and could adversely affect cash generated from operating activities.
FERC has jurisdiction over wholesale rates for all electric energy sold by the Liberty Power Group in the United States. The Liberty Power Group’s facilities in the United States are required to meet the requirements of a “qualified facility” or an “exempt wholesale generator” and, subject to certain exceptions, to obtain and maintain authority from FERC to sell power at market-based rates. The failure of the Liberty Power Group to maintain market-based rate authorization for certain facilities that currently have it would constitute a default under the facility’s power purchase agreement and any project financing for such facility, and could materially and adversely affect the Corporation.
The operations of each of the Corporation’s business units are also subject to a variety of federal, provincial and state environmental and other regulatory bodies, the requirements and regulations of which affect the operations of and costs incurred by the Corporation. In addition, changes in regulations or the imposition of additional regulations also could have a material adverse effect on the Corporation’s results of operations.
The Corporation’s operations are subject to numerous health and safety laws and regulations.
The operation of the Corporation’s facilities requires adherence to safety standards imposed by regulatory bodies. These laws and regulations require the Corporation to obtain approvals and maintain permits, undergo environmental impact assessments and review processes and implement environmental, health and safety programs and procedures to control risks associated with the citing, construction, operation and decommissioning of wind energy projects. Failure to operate the facilities in strict compliance with these regulatory standards may expose the facilities to claims and administrative sanctions.
Health and safety laws, regulations and permit requirements may change or become more stringent. Any such changes could require us to incur materially higher costs than the Corporation has incurred to date. The Corporation’s costs of complying with current and future health and safety laws, regulations and permit requirements, and any liabilities, fines or other sanctions resulting from violations of them, could adversely affect its business, financial condition and results of operations.
The Corporation is subject to numerous environmental laws, regulations and other standards that may result in capital expenditures, increased operating costs and various liabilities.
The Corporation is subject to extensive federal, state, provincial and local regulation with regard to air and other environmental matters. Failure to comply with these laws and regulations could have a material adverse effect on the Corporation’s results

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of operations and financial position. In addition, new environmental laws and regulations and new interpretations of existing environmental laws and regulations, have been adopted and may in the future be adopted, which may substantially increase the Corporation’s future environmental expenditures. Although the Liberty Utilities Group has historically recovered such costs through regulated customer rates, there can be no assurance that the Liberty Utilities Group will recover all or any part of such increased costs in future rate cases. The Liberty Power Group generally has no right to recover such costs from customers. The incurrence of additional material environmental costs which are not recovered in utility rates may result in a material adverse effect on the Corporation’s business, financial condition and results of operations.
The Corporation may pursue growth opportunities in new markets that are subject to foreign laws or regulation that are more onerous than the laws and regulations to which it is currently subject.
The Corporation may pursue growth opportunities in new markets that are subject to regulation by various foreign governments and regulatory authorities and to the application of foreign laws. Such foreign laws or regulations may not provide the same type of legal certainty and rights, in connection with the Corporation’s contractual relationships in such countries, as are afforded to the Corporation currently, which may adversely affect the Corporation’s ability to receive revenues or enforce its rights in connection with any operations in such jurisdictions. In addition, the laws and regulations of some countries may limit the Corporation’s ability to hold a majority interest in certain growth projects, thus limiting the Corporation’s ability to control the operations of such projects. Any existing or new operations may also be subject to significant political, economic and financial risks, which vary by country, and may include: (i) changes in government policies or personnel; (ii) changes in general economic conditions; (iii) restrictions on currency transfer or convertibility; (iv) changes in labour relations; (v) political instability and civil unrest; (vi) regulatory or other changes in the local electricity market; and (vii) breach or repudiation of important contractual undertakings by governmental entities and expropriation and confiscation of assets and facilities for less than fair market value.
4.4 Risk Factors Relating to Strategic Planning and Execution
The Corporation is subject to risks associated with its growth strategy that may adversely affect its business, results of operations, financial condition and cash flows, and actual capital expenditures may be lower than planned.
The Corporation has a history of growth through acquisitions and organic growth from capital expenditures in existing service territories. There is no certainty that the Corporation will be successful in pursuing this growth strategy in the future. There can be no assurance that the Corporation will be able to identify attractive acquisition or development candidates in the future or that it will be able to realize growth opportunities that increase the amount of cash available for distribution. The Corporation may also face significant competition for growth opportunities and, to the extent that any opportunities are identified, may be unable to effect such growth opportunities due to a lack of necessary capital resources. Risks related to capital projects include schedule delays and project cost overruns. Capital expenditures at the utilities are generally approved by the respective regulators, however, there is no assurance that any project cost overruns would be approved for recovery in customer rates.
Any growth opportunity could involve potential risks, including an increase in indebtedness, the potential disruption to the Corporation’s ongoing business, the diversion of management’s attention from other business concerns and the possibility that the Corporation will incur more costs than originally anticipated or, in the case of acquisitions, more than the acquired company or interest is worth. In addition, funding requirements associated with the growth opportunity, including any acquisition, development or integration costs, may reduce the funds available to pay dividends.
The Corporation’s capital expenditure program and associated rate base growth are key assumptions in the Corporation’s targeted dividend growth guidance. Actual capital expenditures may be lower than planned due to factors beyond the Corporation’s control, which would result in a lower than anticipated rate base and have an adverse effect on the Corporation’s results of operations, financial condition and cash flows. This could limit the Corporation’s ability to meet its targeted dividend growth.
The Corporation’s development and construction activities are subject to material risks, including expenditures for projects that may prove not to be viable, construction cost overruns and delays, inaccurate estimates of expected energy output or other factors, and failure to satisfy tax incentive requirements or to meet third-party financing requirements.
The Corporation actively engages in the development and construction of new power generation facilities, and currently has a pipeline of projects in development or construction, consisting mainly of solar and wind power generation projects, as well

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as the development and construction of transmission and distribution assets. In addition, each of the Corporation’s business segments may occasionally undertake construction activities as part of normal course maintenance activities.
Significant costs must be incurred to determine the technical feasibility of a project, obtain necessary regulatory approvals and permits, obtain site control and interconnection rights and negotiate revenue contracts for the facility before the viability of the project can be determined. 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, or the failure of a project to proceed and the resultant loss of amounts invested or expenses already incurred.
Once under construction, material delays or cost overruns could be incurred as a result of vendor or contractor performance, technical issues with the interconnection utility, disputes with landowners or other parties, severe weather and other causes.
The Corporation’s assessment of the feasibility, revenues and profitability of a renewable power generation facility depends upon estimates regarding the strength and consistency of the applicable natural resource (such as wind, solar radiance or hydrology) and other factors, such as assessments of the facility’s potential impact on wildlife. If weather patterns change or actual data proves to be materially different than estimates, the amount of electricity to be generated by the facility and resulting revenues and profitability may differ significantly from expected amounts.
For certain of its development projects, the Liberty Power Group relies on financing from third party tax equity investors, the participation of which depends upon qualification of the project for U.S. tax incentives and satisfaction of the investors’ investment criteria. These investors typically provide funding upon commercial operation of the facility. Should certain facilities not meet the conditions required for tax equity funding, expected returns from the facilities would be adversely impacted.
The Liberty Power Group depends on certain key customers for a significant portion of its revenues. The loss of any key customer or the failure to secure new power purchase agreements or to renew existing power purchase agreements could increase market price risk with respect to the sale of generated energy and renewable energy credits.
A substantial portion of the output of the Liberty Power Group’s power generation facilities is sold under long-term power purchase agreements, under which a single purchaser is obligated to purchase all of the output of the applicable facility and (in most cases) associated renewable energy credits. The termination or expiry of any such power purchase agreement, unless replaced or renewed on equally favorable terms, would adversely affect the Corporation’s results of operations and cash flows and increase the Corporation’s exposure to risks of price fluctuations in the wholesale power market.
Securing new power purchase agreements is a risk factor in light of the competitive environment in which the Corporation operates. The Corporation expects the Liberty Power Group to continue to enter into power purchase agreements for the sale of its power, which power purchase agreements are mainly obtained through participation in competitive requests for proposals processes. During these processes, the Corporation faces competitors ranging from large utilities to small independent power producers, some of which have significantly greater financial and other resources than the Corporation. There can be no assurance that the Corporation will be selected as power supplier following any particular request for proposals in the future or that existing power purchase agreements will be renewed or will be renewed on favourable terms and conditions upon the expiry of their respective terms.
The Corporation may fail to complete planned acquisitions, which may result in a loss of expected benefits from such acquisitions or may generate significant liabilities.
Acquisitions of complementary businesses and technologies are a part of the Corporation’s overall business strategy. Because of the regulated nature of the business sectors in which the Corporation operates, nearly all acquisitions by the Corporation are subject to various regulatory approvals and, consequently, to the risks that such approvals may not be timely obtained or may impose unfavorable conditions that could impair the ability to complete the acquisition or impose adverse conditions on the Corporation following the acquisition.
In addition, the Corporation may enter into acquisition agreements under which the Corporation’s obligations are not contingent upon availability of financing, in which case the Corporation could incur higher than expected financing costs or, if such financing cannot be obtained, significant liability to the seller.

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Failure to complete an acquisition may decrease investor confidence. In addition, the terms of an acquisition agreement may impose liability on the Corporation for failing to complete the acquisition, which in some cases may include liability where the reasons for failure to complete the acquisition are not entirely within the Corporation’s control.
The Corporation may fail to realize the intended benefits of completed acquisitions or may incur unexpected costs or liabilities as a result of completed acquisitions.
The Corporation may not effectively integrate the services, technologies, key personnel or businesses of acquired companies or may not obtain anticipated operating benefits or synergies from completed transactions will not be realized. In addition, the Corporation may incur unexpected costs or liabilities in connection with the closing or integration of any acquisition.
The success of an acquisition may depend on retention of the workforce or key employees of the acquired business. The Corporation may not be successful in retaining such workforce or key employees or in retaining them at anticipated costs.
In addition, the Corporation may be subject to unexpected liabilities, despite any due diligence investigation of an acquired business or any contractual remedies the Corporation may have against the sellers. Detailed information regarding an acquired business is generally available only from the seller, and contractual remedies are typically subject to negotiated limitations. In addition, in cases in which the target company is publicly traded and its shares are widely held, the Corporation is likely not to have recourse following the completion of the acquisition for misrepresentations made to the Corporation in connection with the acquisition.
The Corporation’s anticipated investment in Atlantica will be subject to the risk that Atlantica may make decisions with which the Corporation does not agree or take risks or otherwise act in a manner that does not serve the Corporation’s interests.
Pursuant to the anticipated Atlantica investment, the Corporation will be investing in equity securities of Atlantica, a company that the Corporation does not control. In addition, subject to certain conditions and limited exceptions, the Corporation has agreed not to increase its interest in Atlantica above 41.5%. As a result, this anticipated investment will be subject to a risk that Atlantica may make business, financial or management decisions with which the Corporation does not agree, or that Atlantica’s other stockholders or management of Atlantica may take risks or otherwise act in a manner that does not serve the Corporation’s interests. If any of the foregoing were to occur, the value of the Corporation’s investment could decrease and the Corporation’s financial condition, results of operations and cash flow could be adversely affected.
Dividends declared and paid by Atlantica are made at the discretion of Atlantica’s board of directors. The Corporation will not control the board of directors of Atlantica. Therefore, there can be no assurance that dividends will continue to be paid on Atlantica’s ordinary shares, will continue to be paid at the same rate as is currently being paid or will be paid at any specified target rate.
Demand in the capital markets for Atlantica’s ordinary shares can vary over time for numerous reasons outside of the Corporation’s control, including performance of the Atlantica business and changes in the prospects of Atlantica. Consequently, it may be difficult for the Corporation to dispose of its anticipated interest in Atlantica at favourable times or prices.
The Corporation’s anticipated investment in Atlantica will expose it to certain risks that are particular to Atlantica’s business and the markets in which Atlantica operates.
Atlantica owns, manages and acquires renewable energy, conventional power, electric transmission lines and water assets in jurisdictions where the Corporation does not currently operate, including Mexico, Peru, Chile, Brazil, Uruguay, Spain, Algeria and South Africa. The Corporation, through its anticipated investment in Atlantica, will be indirectly exposed to certain risks that are particular to Atlantica’s business and the markets in which it operates, including, but not limited to, risks related to: conditions in the global economy; changes to national and international laws, political, social and macroeconomic risks relating to the new jurisdictions, including in emerging markets, which could be subject to economic, social and political uncertainties; anti-bribery laws and substantial penalties and reputational damage from any non-compliance therewith; Atlantica’s ability to identify and/or consummate future acquisitions on favourable terms or at all; Atlantica’s inability to replace, on similar or commercially favourable terms, expiring or terminated offtake agreements; reputational risk, including with respect to the reputation of Abengoa; termination or revocation of Atlantica’s concession agreements or power purchase agreements; Abengoa’s ability to meet its obligations under its agreements with Atlantica; and various other factors. These risks could affect the profitability and growth of Atlantica’s business, and ultimately the profitability of the Corporation’s anticipated investment therein.

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The Liberty Utilities Group’s water, wastewater, electricity and natural gas distribution systems could be subject to condemnation or other methods of taking by government entities under certain conditions.
The Liberty Utilities Group’s water, wastewater, electricity and natural gas 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 that just and fair compensation be paid to the Liberty Utilities Group, and the Liberty Utilities Group believes that such compensation generally would reflect fair market value for any assets that are taken. However, the determination of such fair and just compensation will be undertaken pursuant to a legal proceeding and, therefore, there can be no assurance that the value received for those assets would reflect the value the Corporation attributes to such assets, that the value received would be above book value or that the Corporation would not recognize a loss.
Increased external stakeholder activism could have an adverse effect on the Corporation's ability to execute its capital programs.
External stakeholders are increasingly challenging investor-owned utilities in the areas of climate change, sustainability, diversity, utility return on equity and executive compensation. In addition, public opposition to larger infrastructure projects in certain areas is becoming increasingly common, which can challenge a utility’s ability to execute its capital programs. The social acceptance by external stakeholders, including, in some cases, First Nations and other aboriginal peoples, local communities and other interest groups may be critical to the Corporation’s ability to find and develop new sites suitable for viable renewable energy projects. Failure to obtain proper social acceptance for a project may prevent the development and construction of a project and lead to the loss of all investments made in the development and the write-off of such prospective project. Failure to effectively respond to public opposition may adversely affect the Corporation's capital expenditure programs, and, therefore, future organic growth, which could adversely affect its results of operations, financial condition and cash flows.
The Corporation will not have sole control over the projects that invests in with its joint venture partner, Abengoa, or over the revenues and certain decisions associated with those projects, which may limit the Corporation’s flexibility with respect to these projects.
Despite having a 50% equity stake in AAGES, the joint venture involves risks, including, among others, a risk that Abengoa:

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

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

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

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

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

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

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

Further, the Corporation will not have sole control of certain major decisions relating to the projects that the Corporation pursues through AAGES, including, among others, decisions relating to funding and transactions with affiliates.
The Corporation may sell businesses or assets, which may be sold at a loss and which, regardless of the sales price, may reduce total revenues and net income.
The Corporation may from time to time dispose of businesses or assets that the Corporation no longer views as being strategic to the Corporation’s continuing operations. Such disposals may result in recognition of a loss upon such a sale. In addition, as a result of divestitures, the Corporation’s revenues and net income may decrease.
The price of the Corporation’s Common Shares may be volatile and the value of shareholders’ investments could decline.
The trading price and value of, and demand for, the Corporation’s Common Shares will fluctuate and depend on a number of factors, including:

• | the risk factors described in this AIF;

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• | general economic conditions internationally and within Canada and the United States, including changes in interest rates;

• | changes in electricity and natural gas prices;

• | actual or anticipated fluctuations in the Corporation’s quarterly and annual results and those of the Corporation’s competitors;

• | the Corporation’s businesses, operations, results and prospects;

• | future mergers and strategic alliances;

• | market conditions in the energy industry;

• | changes in government regulation, taxes, legal proceedings or other developments;

• | shortfalls in the Corporation’s operating results from levels forecasted by securities analysts;

• | investor sentiment toward the stock of energy companies in general;

• | announcements concerning the Corporation or its competitors;

• | maintenance of acceptable credit ratings or credit quality; and

• | the general state of the securities markets.

These and other factors may impair the development or sustainability of a liquid market for the Common Shares and the ability of investors to sell shares at an attractive price. These factors also could cause the market price and demand for the Common Shares to fluctuate substantially, which may adversely affect the price and liquidity of the Corporation’s Common Shares. These fluctuations could cause shareholders to lose all or part of their investment in Common Shares. Many of these factors and conditions are beyond the Corporation’s control and may not be related to its operating performance.
5. DIVIDENDS
Common Shares
The amount of dividends declared for each Common Share for fiscal 2015, 2016 and 2017 were U.S. $0.38, U.S. $0.41 and U.S. $0.47 respectively.
APUC follows a quarterly dividend schedule, subject to subsequent Board declarations each quarter. APUC’s current quarterly dividend to shareholders is U.S. $0.1165 per common share or U.S. $0.4660 per Common Share per annum.
The Board has adopted a dividend policy to provide sustainable dividends to shareholders, considering cash flow from operations, financial condition, financial leverage, working capital requirements and investment opportunities. The Board can modify the dividend policy from time to time at its discretion. There are no restrictions on the dividend policy of APUC. The amount of dividends declared and paid is ultimately dependent on a number of factors, including the risk factors previously noted, and there is no assurance as to the amount or timing of such dividends in the future. See “Enterprise Risk Factors”.
Preferred Shares
On November 9, 2012, APUC issued 4,800,000 cumulative rate reset Series A preferred shares (the “Series A Shares”). For an initial six year period the holders of Series A Shares are entitled to receive fixed cumulative preferential cash dividends, as and when declared by the Board, payable quarterly on the last business day of March, June, September and December in each year at an annual rate equal to $1.1250 per Series A Share. In each of 2015, 2016 and 2017, dividends of $1.1250 per Series A Share were paid.
On January 1, 2013, the Corporation issued 100 Series C Shares and exchanged such shares for the 100 Class B units of St. Leon LP, including 36 units held indirectly by the Senior Management. The Series C Shares provide dividends essentially identical to that expected from the Class B units. In 2015, 2016 and 2017, dividends paid to Series C preferred shareholders were $9,893, $8,528 and $7,922 per Series C Share respectively.
On March 5, 2014, APUC issued 4,000,000 cumulative rate reset Series D shares (the “Series D Shares”). For an initial five year period the holders of Series D Shares are entitled to receive fixed cumulative preferential cash dividends, as and when declared by the Board, payable quarterly on the last business day of March, June, September and December in each year at

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an annual rate equal to $1.250 per Series D Share. In 2015, 2016, and 2017, dividends of $1.25 per Series D Share were paid.
5.1 Dividend Reinvestment Plan
Under the Reinvestment Plan, holders of Common Shares who reside in Canada or the United States may opt to reinvest the cash dividends paid on their Common Shares in additional Common Shares which, at APUC’s election, will either be purchased on the open market or newly issued from treasury. Common Shares purchased under the Reinvestment Plan are currently being issued from treasury at a 5% discount to the prevailing market price (as determined in accordance with the terms of the Reinvestment Plan). The 5% discount will remain in effect for all cash dividends that may be declared, if any, by the Board until otherwise announced, at its discretion.
6. DESCRIPTION OF CAPITAL STRUCTURE
6.1 Common Shares
The Common Shares are publicly traded on the TSX and the NYSE under the ticker symbol “AQN”. The Corporation has been a U.S. Securities and Exchange Commission registrant since 2009 and operates primarily in the United States.
As at December 31, 2017, APUC had 431,765,935 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.
6.2 Preferred Shares
APUC is also authorized to issue an unlimited number of preferred shares, issuable in one or more series, containing terms and conditions as approved by the Board. As at December 31, 2017, APUC had outstanding:

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

• | 100 Series C Shares; and

• | 4,000,000 Series D Shares, yielding 5.0% annually for the initial five-year period ending on March 31, 2019.

Series A Shares
The Series A Shares rank senior to the Common Shares and rank on parity with every other series of preferred shares as to dividends, may be redeemed by APUC on December 31, 2018 and on December 31 every five years thereafter, are convertible upon the occurrence of certain events into cumulative floating rate preferred shares, Series B (the “Series B Shares”). The Series A Shares rank on a parity with the preferred shares of every other series and senior to the Common Shares upon liquidation, dissolution or winding up of APUC. The Series A Shares are entitled to receive $25.00 per Series A Share plus all accrued and unpaid dividends thereon, but are not entitled to share in any further distribution of the assets of APUC.
Series B Shares
APUC is authorized to issue up to 4,800,000 Series B Shares upon the conversion of Series A Shares upon the occurrence of certain events. Series B Shares rank senior to the Common Shares and rank on parity with every other series of preferred shares as to dividends, may be redeemed by APUC on any Series B Conversion Date (as defined in the articles of APUC), and are convertible into Series A Shares upon the occurrence of certain events. The Series B Shares rank on a parity with the preferred shares of every other series and senior to the Common Shares upon liquidation, dissolution or winding up of APUC. The Series B Shares are entitled to receive $25.00 per Series B Share plus all accrued and unpaid dividends thereon, but are not entitled to share in any further distribution of the assets of APUC.

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Series C Shares
The Series C preferred shares (the “Series C Shares”) rank senior to the Common Shares and rank on parity with every other series of preferred shares as to dividends and are entitled to cumulative dividends in accordance with the formula set forth in the articles of APUC. The Series C Shares rank on a parity with the preferred shares of every other series and senior to the Common Shares upon liquidation, dissolution or winding up of APUC. The Series C Shares are entitled to receive the redemption price calculated in accordance with the share terms plus all accrued and unpaid dividends thereon, but are not entitled to share in any further distribution of the assets of APUC. The Series C Shares are redeemable upon the occurrence of certain events. During the period between May 20, 2031 and June 19, 2031, the Series C Preferred Shares are convertible into Common Shares and, if not so converted, will be automatically redeemed on June 19, 2031. Holders of the Series C Preferred Shares include a partnership controlled by Ian Robertson, Chief Executive Officer of the Corporation and a partnership controlled by Chris Jarratt, Vice Chairman of the Corporation.
Series D Shares
The Series D Shares rank senior to the Common Shares and rank on parity with every other series of preferred shares as to dividends, may be redeemed by APUC on March 31, 2019 and on March 31 every five years thereafter, and are convertible upon the occurrence of certain events into cumulative floating rate preferred shares, Series E (the “Series E Shares”). The Series D Shares rank on a parity with the preferred shares of every other series and senior to the Common Shares upon liquidation, dissolution or winding up of APUC. The Series D Shares are entitled to receive $25.00 per Series D Share plus all accrued and unpaid dividends thereon, but are not entitled to share in any further distribution of the assets of APUC.
Series E Shares
APUC is authorized to issue up to 4,000,000 Series E Shares upon the conversion of Series D Shares upon the occurrence of certain events. The Series E Shares rank senior to the Common Shares and rank on parity with every other series of preferred shares as to dividends, may be redeemed by APUC on any Series E Conversion Date (as defined in the articles of APUC), and are convertible into Series D Shares upon the occurrence of certain events. The Series E Shares rank on a parity with the preferred shares of every other series and senior to the Common Shares upon liquidation, dissolution or winding up of APUC. The Series E Shares are entitled to receive $25.00 per Series E Share plus all accrued and unpaid dividends thereon, but are not entitled to share in any further distribution of the assets of APUC.
Subject to applicable corporate law, the outstanding preferred shares are non-voting and not entitled to receive notice of any meeting of shareholders, except that the Series A Shares and Series D Shares (and the Series B Shares and Series E Shares, respectively, into which they are convertible) will be entitled to one vote per share if APUC shall have failed to pay eight quarterly dividends on such shares. The outstanding preferred shares do not have a right to participate in a take-over bid of the Common Shares of APUC.

6.3 | Convertible Debentures

On February 9, 2016, in connection with the Empire Acquisition, APUC completed the sale of the Debentures.
The Debentures will mature on March 31, 2026. The Debentures accrued interest at an annual rate of 5% per $1,000 dollars principal amount of Debentures until and including February 2, 2017, after which the interest rate became 0%.
At the option of the holders, each Debenture is convertible into Common Shares at any time prior to the earlier of maturity or redemption by APUC, at a conversion price of $10.60 per Common Share. APUC will issue up to 108,490,566 Common Shares on conversion of all of the Debentures. To date, a total of 108,384,716 Common Shares were issued, representing conversion into Common Shares of more than 99.9% of the Debentures. At maturity, APUC will have the right to pay the principal amount due in cash or in Common Shares. In the case of Common Shares, such shares will be valued at 95% of their weighted average trading price on the TSX for the 20 consecutive trading days ending five trading days preceding the maturity date.

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6.4 | Shareholders’ Rights Plan

The shareholders' rights plan, as amended and restated in 2016 (the “Amended and Restated Rights Plan”) is designed to ensure the fair treatment of shareholders in any transaction involving a potential change of control of APUC and will provide the Board and shareholders with adequate time to evaluate any unsolicited take-over bid and, if appropriate, to seek out alternatives to maximize shareholder value.
Until the occurrence of certain specific events, the rights will trade with the Common Shares and be represented by certificates representing the Common Shares. The rights become exercisable only when a person, including any party related to it or acting jointly with it (subject to certain exceptions), acquires or announces its intention to acquire twenty percent or more of the outstanding Common Shares without complying with the permitted bid provisions of the Plan. Should a non-permitted bid be launched, each right would entitle each holder of shares (other than the acquiring person and persons related to it or acting jointly with it) to purchase additional Common Shares at a fifty percent discount to the market price at the time.
It is not the intention of the Amended and Restated Rights Plan to prevent take-over bids but to ensure their proper evaluation by the market. Under the Amended and Restated Rights Plan, a permitted bid is a bid made to all shareholders for all of their Common Shares on identical terms and conditions that is open for no less than 105 days. If at the end of 105 days at least fifty percent of the outstanding Common Shares, other than those owned by the offeror and certain related parties, have been tendered and not withdrawn, the offeror may take up and pay for the Common Shares but must extend the bid for a further ten days to allow all other shareholders to tender.
The Amended and Restated Rights Plan will remain in effect until the termination of the annual meeting of the shareholders of APUC in 2019 or its termination under the terms of the of Amended and Restated Rights Plan. The Amended and Restated Rights Plan is similar to rights plans adopted by many other Canadian corporations.
7. MARKET FOR SECURITIES
7.1 Trading Price and Volume

7.1.1 | Common Shares

The Common Shares are listed and posted for trading on the TSX and NYSE under the symbol “AQN”. The following table sets forth the high and low trading prices and the aggregate volumes of trading of the Common Shares for the periods indicated (as quoted by the TSX and NYSE).

| TSX | NYSE
2017 | High ($) | Low ($) | Volume | High (US$) | Low (US$) | Volume
January | 11.48 | 11.15 | 37,934,616 | 8.79 | 8.33 | 347,242
February | 12.29 | 11.33 | 28,660,212 | 9.35 | 8.68 | 355,634
March | 12.98 | 11.98 | 24,143,635 | 9.71 | 9.00 | 323,442
April | 13.05 | 12.57 | 17,211,371 | 9.74 | 9.38 | 242,782
May | 13.98 | 12.90 | 19,040,345 | 10.35 | 9.44 | 282,999
June | 14.35 | 13.26 | 16,660,457 | 10.80 | 10.21 | 273,733
July | 13.70 | 12.90 | 18,919,660 | 10.85 | 10.00 | 316,009
August | 13.83 | 13.10 | 12,252,860 | 11.02 | 10.33 | 327,519
September | 13.59 | 12.91 | 17,566,633 | 11.20 | 10.50 | 447,560
October | 14.145 | 13.18 | 18,200,984 | 11.21 | 10.56 | 500,870
November | 14.40 | 12.99 | 30,208,784 | 11.34 | 10.13 | 813,669
December | 14.33 | 13.86 | 15,101,341 | 11.22 | 10.80 | 472,775

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7.1.2 | Preferred Shares

Series A Shares
The Series A Shares are listed and posted for trading on the TSX under the symbol “AQN.PR.A”. The following table sets forth the high and low trading prices and the aggregate volume of trading of the Series A Shares for the periods indicated (as quoted by the TSX).

2017 | High ($) | Low ($) | Volume
January | 21.59 | 19.62 | 71,411
February | 22.00 | 21.45 | 76,083
March | 22.77 | 21.34 | 130,552
April | 23.15 | 21.68 | 52,280
May | 22.82 | 21.62 | 108,755
June | 23.44 | 22.11 | 154,745
July | 24.43 | 23.15 | 325,970
August | 24.02 | 22.55 | 190,566
September | 23.34 | 22.50 | 42,044
October | 24.00 | 23.00 | 84,596
November | 24.20 | 23.10 | 59,700
December | 24.10 | 23.52 | 39,533

Series D Shares
The Series D Shares are listed and posted for trading on the TSX under the symbol “AQN.PR.D”. The following table sets forth the high and low trading prices and the aggregate volume of trading of the Series D Shares for the periods indicated (as quoted by the TSX).

2017 | High ($) | Low ($) | Volume
January | 24.32 | 22.90 | 133,516
February | 24.42 | 23.80 | 114,078
March | 24.62 | 22.95 | 86,538
April | 24.50 | 23.73 | 19,168
May | 24.40 | 23.16 | 48,047
June | 24.59 | 23.40 | 55,076
July | 25.00 | 24.22 | 163,059
August | 24.92 | 23.63 | 46,036
September | 25.05 | 23.81 | 40,283
October | 25.30 | 25.00 | 33,432
November | 25.98 | 25.14 | 24,310
December | 25.50 | 24.90 | 96,914

7.2 Prior Sales
During the year ended December 31, 2017, there were no Series C Shares issued by APUC.
7.3 Escrowed Securities and Securities Subject to Contractual Restrictions on Transfer
There are no securities of APUC that are subject to contractual restrictions on transfer as of the date of this AIF.

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8. DIRECTORS AND OFFICERS
8.1 Name, Occupation and Security Holdings
The following table sets forth certain information with respect to the directors and executive officers of APUC, and information on their history with APCo and APUC. Unless otherwise indicated, the individuals have been in their principal occupations for more than five years.

Name and Place of Residence | Principal Occupation | Served as Director or Officer of APUC from
CHRISTOPHER J. BALL Toronto, Ontario, Canada Age: 67 | Christopher Ball is the Executive Vice President of Corpfinance International Limited, and President of CFI Capital Inc., both of which are boutique investment banking firms. From 1982 to 1988, Mr. Ball was Vice President at Standard Chartered Bank of Canada with responsibilities for the Canadian branch operation. Prior to that, Mr. Ball held various managerial positions with the Canadian Imperial Bank of Commerce. He is also a member of the Hydrovision International Advisory Board, was a director of Clean Energy BC, and is a recipient of the Clean Energy BC Lifetime Achievement Award. | Director of APUC since October 27, 2009 Trustee of APCo from October 22, 2002 until May 12, 2011
DAVID BRONICHESKI Oakville, Ontario, Canada Age: 58 | Mr. Bronicheski is the Chief Financial Officer of APUC. He has held various senior management positions including Executive Vice President and CFO of a publicly traded income trust providing local telephone, cable television and internet service. He was also CFO for a large public hospital in Ontario. Mr. Bronicheski holds a Bachelor of Arts in economics (cum laude), a Bachelor of Commerce degree and an MBA (University of Toronto, Rotman School of Management). He is also a Chartered Accountant and a Chartered Professional Accountant. | Officer of APUC since October 27, 2009 Officer of APCo since September 17, 2007
CHRISTOPHER K. JARRATT Oakville, Ontario, Canada Age: 59 | Christopher Jarratt has over 25 years of experience in the independent electric power and utility sectors and is Vice Chair of APUC. Mr. Jarratt is a founder and principal of APCI, a private independent power developer formed in 1988 which is the predecessor organization to APCo and APUC. Between 1997 and 2009, Mr. Jarratt was a principal in Algonquin Power Management Inc. which managed APCo (formerly Algonquin Power Income Fund). Since 2010, Mr. Jarratt has been a board member and served as Vice Chair of APUC. Prior to 1988, Mr. Jarratt was a founder and principal of a consulting firm specializing in renewable energy project development and environmental approvals. Mr. Jarratt earned an Honours Bachelor of Science degree from the University of Guelph in 1981 specializing in water resources engineering and holds an Ontario Professional Engineering designation. In 2009, Mr. Jarratt completed the Chartered Director program of the Directors College (McMaster University) and holds the certification of Ch. Dr. (Chartered Director). In addition, Mr. Jarratt was co-recipient of the 2007 Ernst & Young Entrepreneur of the Year finalist award. | Director of APUC since June 23, 2010
D. RANDY LANEY Farmington, Arkansas, USA Age: 63 | D. Randy Laney was most recently Chairman of the Board of Empire District Electric Company since 2009. He joined the Board of Empire in 2003 serving as the Non-Executive Vice Chairman of the Board from 2008 to 2009 and Non-Executive Chairman of the Board from April 23, 2009 until APUC's acquisition of Empire on January 1, 2017. Mr. Laney, semi-retired since 2008, has held numerous senior level positions with both public and private companies during his career, including 23 years with Wal-Mart Stores, Inc. in various executive positions including Vice President of Finance, Benefits and Risk Management and Vice President of Finance and Treasurer. In addition, Mr. Laney has provided strategic advisory services to both private and public companies and served on numerous profit and non-profit boards. Mr. Laney brings significant management and capital markets experience, and strategic and operational understanding to his position on the Board. | Director of APUC since February 1, 2017
KENNETH MOORE Toronto, Ontario, Canada Age: 59 | Kenneth Moore is the Managing Partner of NewPoint Capital Partners Inc., an investment banking firm. From 1993 to 1997, Mr. Moore was a senior partner at Crosbie & Co., a Toronto mid-market investment banking firm. Prior to investment banking, he was a Vice-President at Barclays Bank where he was responsible for a number of leveraged acquisitions and restructurings. Mr. Moore holds a Chartered Financial Analyst designation. Additionally, he has completed the Chartered Director program of the Directors College (McMaster University) and has the certification of Ch. Dir. (Chartered Director). | Director of APUC since October 27, 2009 Trustee of APCo from December 18, 1998 until November 10, 2010

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Name and Place of Residence | Principal Occupation | Served as Director or Officer of APUC from
JEFF NORMAN Burlington, Ontario, Canada Age: 49 | Jeff Norman is the Chief Development Officer of the Corporation, serving in this role since 2008. He was appointed to the APUC executive team in 2015. Mr. Norman co-founded the Algonquin Power Venture Fund in 2003 and served as President until it was acquired by APCo in 2008. Since 2008 the business development team has secured over 1 gigawatt of commercially secure renewable energy projects. Mr. Norman has over 24 years of experience and has reviewed the economic merits of hundreds of renewable energy projects located throughout North America. | Officer of APUC since May 25, 2015
DAVID PASIEKA Oakville, Ontario, Canada Age: 61 | David Pasieka is the Chief Operating Officer of APUC's Liberty Utilities Group. As Chief Operating Officer, Mr. Pasieka is focused on acquiring and managing a portfolio of regulated water, natural gas and electrical companies throughout the United States. The focus of the portfolio is in the distribution, transmission, and generation sectors. Mr. Pasieka has global experience in strategy, sales, marketing, integration, operations and customer service. He has led many organizations while integrating people, process and technology to encourage the steady growth of the organizations. Mr. Pasieka holds a Bachelor of Science Degree from the University of Waterloo, Masters of Business Administration from the Schulich School of Business – York University and a Chartered Director designation from McMaster University. | Officer of APUC since September 1, 2011
IAN E. ROBERTSON Oakville, Ontario, Canada Age: 58 | Ian Robertson is the Chief Executive Officer of the Corporation. Mr. Robertson is a founder and principal of APCI, a private independent power developer formed in 1988 which was a predecessor organization to APUC. Mr. Robertson has almost 30 years of experience in the development of electric power generating projects and the operation of diversified regulated utilities. Mr. Robertson is an electrical engineer and holds a Professional Engineering designation through his Bachelor of Applied Science degree awarded by the University of Waterloo. Mr. Robertson earned a Master of Business Administration degree from York University and holds a Chartered Financial Analyst designation. Additionally, he has completed the Chartered Director program of the Directors College (McMaster University), as well as a Global Professional Master of Laws degree from the University of Toronto and has the certification of Ch. Dir. (Chartered Director). Commencing in 2013, Mr. Robertson has served on the Board of Directors of the American Gas Association. | Director of APUC since June 23, 2010.
MASHEED SAIDI Dana Point, California, United States Age: 63 | Masheed Saidi has over 30 years of operational and business leadership experience in the electric utility industry. Between 2010 and 2017, Ms. Saidi was an Executive Consultant of Energy Initiatives Group, a specialized group of experienced professionals that provide technical, commercial and business consulting services to utilities, ISOs, government agencies and other organizations in the energy industry. Between 2005 and 2010, Ms. Saidi was the Chief Operating Officer and Executive Vice President of U.S. Transmission for National Grid USA, for which she was responsible for all aspects of U.S. transmission business. Ms. Saidi previously served as Chairperson of the Board of Directors for the non-profit organization, Mary’s Shelter, and also previously served on the Board of Directors of the Northeast Energy and Commerce Association. She earned her Bachelors in Power System Engineering from Northeastern University and her Masters of Electrical Engineering from the Massachusetts Institute of Technology. She is a Registered Professional Engineer (P.E.). | Director of APUC since June 18, 2014
DILEK SAMIL Las Vegas, Nevada, United States Age: 62 | Dilek Samil has over 30 years of finance, operations and business experience in both the regulated energy utility sector as well as wholesale power production. Ms. Samil joined NV Energy as Chief Financial Officer and retired as Executive Vice President and Chief Operating Officer. While at NV Energy, Ms. Samil completed the financial transformation of the company, bringing its financial metrics in line with those of the industry. As Chief Operating Officer, Ms. Samil focused on enhancing the company's safety and customer care culture. Prior to her role at NV Energy, Ms. Samil gained considerable experience in generation and system operations as President and Chief Operating Officer for CLECO Power. During her tenure at CLECO, the company completed construction of its largest generating unit and successfully completed its first rate case in over 10 years. Ms. Samil also served as CLECO's Chief Financial Officer at a time when the industry and the company faced significant turmoil in the wholesale markets. She led the company's efforts in the restructuring of its wholesale and power trading activities. Prior to NV Energy and Cleco, Ms. Samil spent about 20 years at NextEra where she held positions of increasing responsibility, primarily in the finance area. Ms. Samil holds a Bachelor of Science from the City College of New York and a Masters of Business Administration from the University of Florida. | Director of APUC since October 1, 2014

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Name and Place of Residence | Principal Occupation | Served as Director or Officer of APUC from
MIKE SNOW Markham, Ontario, Canada Age: 57 | Mike joined APUC in 2011 and serves as Chief Operating Officer of APUC's Liberty Power Group. He is responsible for all aspects of strategy, business development, operations, asset management, human resources, and evaluating and reporting on growth and operational activities. Mike has led both industrial and consumer organizations focused on growth and international operations in Mexico, South America, and Asia, while driving culture change and building strong leadership teams. Mike holds a Bachelor of Science Degree in Math from Dalhousie University, a Bachelor of Engineering Degree (Mechanical) from the Technical University of Nova Scotia, and a Masters of Business Administration from the Ivey School of Business - Western University. Mike received his Chartered Director designation from McMaster University in 2014 and sits on the Board of Governors of the University of Ontario Institute of Technology. | Officer of APUC since July 4, 2011
MELISSA STAPLETON BARNES Age: 49 Carmel, Indiana, United States of America | Melissa Stapleton Barnes has been Senior Vice President, Enterprise Risk Management, and Chief Ethics and Compliance Officer for Eli Lilly and Company since January, 2013. Reporting directly to the CEO and Board of Directors, she is an executive officer and serves as a member of the company’s executive committee. She previously held the role of Vice President, Deputy General Counsel from 2012 to 2013; and General Counsel, Lilly Diabetes and Lilly Oncology and Senior Director and Assistant General Counsel from 2010 - 2012. She holds a Bachelor of Science in Political Science & Government (highest distinction) from Purdue University and a Juris Doctorate from Harvard Law School. Ms. Barnes is a member of several professional organizations including Ethisphere - Business Ethics Leadership Alliance; CEB, Corporate Ethics Leadership Council; Conference Board, Global Council on Business Conduct; Healthcare Businesswomen’s Association, and is a Licensed Attorney with the Indiana State Bar. Other board positions include The Center for the Performing Arts (Vice Chair), Visit Indy, The Children’s Museum, and The Great American Songbook. | Director of APUC since June 9, 2016
GEORGE L. STEEVES Aurora, Ontario, Canada Age: 68 | George Steeves has been Senior Project Manager of True North Energy, an energy consulting firm specializing in the provision of technical and financial due diligence services for renewable energy projects, since July 2017. From April 2002 to July 2017, Mr. Steeves was principal of True North Energy. From January 2001 to April 2002, Mr. Steeves was a division manager of Earthtech Canada Inc. Prior to January 2001, he was the President of Cumming Cockburn Limited, an engineering firm, and has extensive financial expertise in acting as a chair, director and/or audit committee member of public and private companies, including the Corporation, and formerly Borealis Hydroelectric Holdings Inc. and KMS Power Income Fund. Mr. Steeves received a Bachelor and Masters of Engineering from Carleton University and holds the Professional Engineering designation in Ontario and British Columbia. Additionally he has completed the Chartered Director program of the Directors College (McMaster University) and has the certification of Ch. Dir. (Chartered Director). | Director of APUC since October 27, 2009 Trustee of APCo from September 8, 1997 until May 12, 2011
JENNIFER TINDALE Campbellville, Ontario, Canada Age: 46 | Jennifer Tindale is the Chief Legal Officer of the Corporation. Ms. Tindale has over 20 years of experience advising public companies on acquisitions, dispositions, mergers, financings, corporate governance and disclosure matters. From July, 2011 to February, 2017, Ms. Tindale was the Executive Vice President, General Counsel & Secretary at a cross-listed real estate investment trust. Prior to that, she was Vice President, Associate General Counsel & Corporate Secretary at a public Canadian-based pharmaceutical company and before that she was a partner at a top tier Toronto law firm, practising corporate securities law. Ms. Tindale holds a Bachelor of Arts and a Bachelor of Laws from the University of Western Ontario. | Officer of APUC since February 7, 2017
GEORGE TRISIC Oakville, Ontario, Canada Age: 57 | George Trisic is the Chief Administrative Officer and Corporate Secretary for the Corporation. He has broad experience managing in high growth, start up and expanding businesses across multiple sites and regions. In his role, Mr. Trisic is responsible for shared services for the Corporation including information technology, human resources, communications, and procurement, and is a well-regarded team builder and business partner. His skill set includes leading multi-functional groups in finance, human resources, legal, and information technology in a senior role. Mr. Trisic holds a Bachelor of Laws Degree from the University of Western Ontario. Additionally, he has completed the Chartered Director program of the Directors College (McMaster University) and has the certification of Ch. Dir. (Chartered Director). | Officer of APUC since November 4, 2013

Each director will serve as a director of APUC until the next annual meeting of shareholders or until his or her successor is elected in accordance with the by-laws of APUC.
As at March 7, 2018, the directors and executive officers of APUC, as a group, beneficially owned, directly or indirectly, or exercised control or direction over 5,091,086 Common Shares, representing less than one percent of the total number of Common Sha

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res outstanding before giving effect to the exercise of options or warrants to purchase Common Shares held by such directors and executive officers. The statement as to the number of Common Shares beneficially owned, directly or indirectly, or over which control or direction is exercised by the directors and executive officers of APUC as a group is based upon information furnished by the directors and executive officers.
8.2 Audit Committee
Under the by-laws of APUC, the directors may appoint from their number, committees to effect the administration of the director’s duties. The directors have established an Audit Committee currently comprised of four directors of APUC, Mr. Ball (Chair), Ms. Stapleton Barnes, Mr. Laney and Ms. Samil, all of whom are independent and financially literate for purposes of National Instrument 52-110 - Audit Committees. The Audit Committee is responsible for reviewing significant accounting, reporting and internal control matters, reviewing all published quarterly and annual financial statements and recommending their approval to the Directors and assessing the performance of APUC’s auditors.

8.2.1 | Audit Committee Charter

The charter for the Audit Committee is attached as Schedule F to this AIF.

8.2.2 | Relevant Education and Experience

The following is a description of the education and experience, apart from their roles as directors of APUC, of each member of the Audit Committee that is relevant to the performance of their responsibilities as a member of the Audit Committee.
Mr. Ball’s financial experience includes over 30 years of domestic and international lending experience. He is Executive Vice-President of Corpfinance International Limited, a privately owned long-term debt and securitization financier. Mr. Ball was formerly a Vice-President at Standard Chartered Bank of Canada with responsibilities for the Canadian branch operation. Prior to that, Mr. Ball held numerous positions with Canadian Imperial Bank of Commerce, including credit function responsibilities. Mr. Ball is the Chair of the Audit Committee.
Mr. Laney’s financial experience includes a number of senior executive roles with Wal-Mart Stores, Inc. including roles as Vice President, Finance and Treasurer and as Vice President Finance, Benefits and Risk Management. Mr. Laney has also served as member of the Board of the Empire District Electric Company commencing in 2003 and as board Chair of that company from 2009 to 2016. Mr. Laney was also a member of the Audit Committee of the Empire District Electric Company from May 2003 to April 2005.
Ms. Samil has extensive financial experience, with over 30 years of finance, operations and business experience in the regulated energy utility sector. During her career, Ms. Samil was the Executive Vice President and Chief Operating Officer of NV Energy and gained considerable experience in generation and system operations as President and Chief Operating Officer for CLECO Power LLC. Ms. Samil holds a Bachelor of Science from the City College of New York and a Masters of Business Administration from the University of Florida.
Ms. Stapleton-Barnes' financial experience includes a number of risk management and legal/regulatory senior executive roles in a public company. Ms. Stapleton-Barnes is currently an executive officer and a member of the corporate executive committee of Eli-Lilly and Company. She has extensive experience in the areas of risk management, legal and regulatory and is a licensed attorney with the Indiana State Bar.

8.2.3 | Pre-Approval Policies and Procedures

The Audit Committee has established a policy requiring pre-approval by the Audit Committee of all audit and permitted non-audit services provided to APUC by its external auditor. The Audit Committee may delegate pre-approval authority to a member of the Audit Committee; however, the decisions of any member of the Audit Committee to whom this authority has been delegated must be presented to the full Audit Committee at its next scheduled Audit Committee meeting.

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Services | 2017 Fees ($) | 2016 Fees ($) | 2015 Fees ($)
Audit Fees 1 | 3,947,930 |  | 3,184,020 |  | 2,420,650 |
Audit-Related Fees 2 | 100,235 |  | 113,414 |  | 98,835 |
Other Tax Fees 3 | 252,535 |  | 269,631 |  | 395,100 |

1 | For professional services rendered for audit or review or services in connection with statutory or regulatory filings or engagements.
2 | For assurance and related services that are reasonably related to the performance of the audit or review of APUC's financial statements and not reported under Audit Fees, including audit procedures related to regulatory commission filings and translation services.
3 | For tax advisory and planning services.

8.3 Corporate Governance, Risk and Compensation Committees
The Board has established a Corporate Governance Committee, currently comprised of four of the directors of APUC: Mr. Steeves (Chair), Mr. Moore, Ms. Saidi, and Mr. Jarratt.
In 2017, the Board has established a Risk Committee to assist the board in the oversight of the Corporation’s enterprise risk management approach. The committee is currently comprised of four directors of APUC, Ms. Saidi (Chair), Ms. Stapleton Barnes, Mr. Jarratt and Mr. Steeves.
The directors have also put in place a Compensation Committee, currently comprised of three directors of APUC, Ms. Samil (Chair), Mr. Ball and Mr. Laney.
8.4 Bankruptcies
Mr. Moore was a director of Telephoto Technologies Inc., a private sports and entertainment media company. Telephoto Technologies Inc. was placed into receivership in August, 2010 by Venturelink Funds. Mr. Moore resigned from the board of directors of Telephoto Technologies Inc. in April, 2010.
8.5 Potential Material Conflicts of Interest
Other than as disclosed elsewhere in this AIF (see “Description of the Business - Related Party Transactions”), to the knowledge of the directors and executive officers of APUC there are no existing or potential material conflicts of interest between APUC or a subsidiary and any current director or officer of APUC or a subsidiary of APUC.
9. LEGAL PROCEEDINGS AND REGULATORY ACTIONS
9.1 Legal Proceedings
Except as disclosed elsewhere in this AIF, there are no legal proceedings involving the Corporation that were material in 2017 or that the Corporation knows to be contemplated.
9.2 Regulatory Actions
Except as disclosed elsewhere in this AIF, during the financial year ended December 31, 2017, there have been:

(a) | no penalties or sanctions imposed against APUC by a court relating to securities legislation or by a securities regulatory authority;

(b) | no other penalties or sanctions imposed by a court or regulatory body against APUC that would likely be considered important to a reasonable investor in making an investment decision; or

(c) | no settlement agreements that APUC has entered into with a court relating to securities legislation or with a securities regulatory authority.

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Except as disclosed elsewhere in this AIF, the only regulatory action involving the Corporation that was material in 2017 is as follows:

(i) | Mountain Water Condemnation

On May 6, 2014, the City of Missoula, Montana filed a lawsuit against Mountain Water Company and its prior indirect owner Carlyle Infrastructure Partners, L.P. (“Carlyle”), seeking to condemn the assets of Mountain Water. The case went to trial on the right to take or “necessity” phase in March, 2015. The District Court issued a Preliminary Order of Condemnation on June 15, 2015, finding that the City had established the right to take the assets of Mountain Water. Mountain Water filed an appeal with the Montana Supreme Court. The case then proceeded to a trial on valuation before three Commissioners. On November 17, 2015, the Commissioners issued a report finding that the “fair market value” of the condemned property as of May 6, 2014 was U.S. $88.6 million. On August 2, 2016, the Supreme Court of Montana upheld the District Court’s decision, permitting the City of Missoula to proceed with the condemnation of Mountain Water’s assets.
On December 22, 2015, certain developers filed a lawsuit in Montana District Court against the City of Missoula and Mountain Water seeking resolution of claims to a portion of the condemnation award on the basis that certain of the assets being condemned had been funded by such parties. On February 21, 2017, the court in that case recognized an equitable lien on such assets in favor of the developers and ordered that a portion of the condemnation award, if and when paid, be paid by the City of Missoula to the court for direct payment to the developers.
On or about June 5, 2017, Mountain Water, Liberty Utilities Co. and the City of Missoula entered into a Settlement Agreement and Release of Claims, resolving certain issues in the event that the City acquired possession of Mountain Water’s assets, and contingent upon settlement of the developer lawsuit. The settlement agreement was approved by the condemnation court in hearings on June 15 and June 22, 2017, and a final order of condemnation was issued on June 22, 2017. The developer lawsuit was dismissed on June 30, 2017. On June 22, 2017, the City of Missoula paid the condemnation judgment, including amounts owed to Mountain Water and amounts required to be paid to the developers. The City of Missoula took possession of Mountain Water’s assets on that date. Carlyle and Mountain Water have appealed certain elements of the final order of condemnation including, among other issues, recovery of post-summons interest and attorney’s fees.
(ii) Apple Valley Condemnation
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. The Town seeks to condemn the utility assets of Apple Valley and to acquire a determination of fair market value. In the first phase of the case, the Court will determine the necessity of the taking by the Town. If the Court determines that necessity has been established, in a second phase, a jury will determine the fair market value of the assets being condemned. The condemnation case is currently proceeding in discovery. Resolution of the condemnation proceedings is expected to take two to three years. 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 and denied Liberty Utilities (Apple Valley Ranchos Water) Corp.s CEQA claim. As a result, the condemnation case will proceed. The Court has set a scheduling conference for the condemnation case in March, 2018 to potentially set a trial date on the first phase of the condemnation action.
10. INTEREST OF MANAGEMENT AND OTHERS IN MATERIAL TRANSACTIONS
Other than as disclosed elsewhere in this AIF, no director, executive officer or principal holder of securities, or any associate or affiliate of the foregoing has, or has had, any material interest in any transaction within the three most recently completed financial years or during the current financial year that has materially affected or will materially affect APUC or any of its affiliates.

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11. TRANSFER AGENTS AND REGISTRARS
The transfer agent and registrar for the Common Shares, the Series A Shares, and the Series D Shares listed on the TSX is AST Trust Company (Canada), at its offices in Toronto, Montréal, Vancouver, Calgary, and Halifax.
The transfer agent and registrar for the Common Shares listed on the NYSE is AST American Stock Transfer & Trust Company, LLC, at its office in Brooklyn, NY.
12. MATERIAL CONTRACTS
Except for certain contracts entered into in the ordinary course of business of the Corporation, the contracts described below are the only contracts entered into by the Corporation during 2017 (or prior to 2017 in the case of contracts that are still in effect) that are material to the Corporation:

(a) | Atlantica Share Purchase Agreement: APUC entered into a sale and purchase agreement dated November 2, 2017, as amended, with ACIL Luxco 1, S.A. and Abengoa providing for the purchase by APUC from ACIL Luxco 1, S.A. of a 25% equity interest in Atlantica for a total purchase price of approximately U.S. $608 million plus a contingent payment payable two years after closing, subject to certain conditions. See “General Development of the Business – Three Year History and Significant Acquisitions – Fiscal 2017”.

(b) | Underwriting Agreement: Underwriting Agreement dated November 3, 2017, between APUC and Scotia Capital Inc., CIBC World Markets Inc. and TD Securities Inc. as co-lead underwriters, in connection with an offering of Common Shares which closed on November 10, 2017. See “General Development of the Business – Fiscal 2017 – Bought Deal Offering of Common Shares”.

(c) | APCo debentures: APCo Trust Indenture between APCo and BNY Trust Company of Canada dated July 25, 2011 providing for the issuance of senior unsecured debentures, as supplemented from time to time, including by the Fourth Supplemental Trust Indenture dated January 17, 2017 providing for the issuance of $300,000,000 4.09% senior unsecured debentures due February 17, 2027.

(d) | U.S. Debt Private Placements: Trust Indenture dated July 2, 2012 between Liberty Utilities Finance GP 1 and The Bank of New York Mellon providing for the creation and issuance of senior unsecured debentures, as supplemented from time to time.

(e) | Empire Acquisition: Agreement and Plan of Merger, dated as of February 9, 2016, by and among Empire, Liberty Utilities (Central) Co., and Liberty Utilities (Sub) Corp. pursuant to which Liberty Utilities (Central) Co. agreed to acquire Empire and (indirectly) its subsidiaries by merger of Liberty Sub Corp. with and into Empire. APUC guaranteed the payment and performance of all obligations of Liberty Utilities (Central) Co. under the Agreement and Plan of Merger pursuant to a Guarantee dated as of February 9, 2016, by APUC in favour of Empire.

(f) | Underwriting Agreement: Underwriting Agreement dated February 15, 2016, between LU Canada, as the selling debenture holder, and CIBC World Markets Inc. and Scotia Capital Inc. as co-lead underwriters, providing for the issuance and sale of not less than $1,000,000,000 and up to $1,150,000,000 principal amount of Debentures in connection with the Debenture Offering.

(g) | Trust Indenture: Trust Indenture dated as of March 1, 2016, between APUC and CST Trust Company, as trustee, providing for the creation and issuance of up to $1,150,000,000 principal amount of Debentures in connection with the Debenture Offering, as supplemented by a supplemental trust indenture dated January 31, 2017.

13. INTERESTS OF EXPERTS
Ernst & Young LLP is the external auditor of the Corporation and has confirmed that it is independent with respect to the Corporation within the meaning of the relevant rules and related interpretations prescribed by the relevant professional bodies in Canada and any applicable legislation or regulation, and that it is an independent accountant with respect to the Corporation under all relevant U.S. professional and regulatory standards.

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14. ADDITIONAL INFORMATION
Additional information relating to APUC may be found on SEDAR at www.sedar.com. Additional information, including directors’ and officers’ remuneration and indebtedness, principal holders of APUC’s securities and securities authorized for issuance under equity compensation plans is contained in APUC’s information circular for its most recent annual meeting. Additional financial information is provided in APUC’s financial statements and MD&A for the fiscal year ended December 31, 2017, which are available on SEDAR at www.sedar.com and on EDGAR at www.sec.gov/edgar.

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SCHEDULE A
Renewable – Selected Hydroelectric, Solar and Wind Facilities

Generating Facility/Owner | Generating Capacity (MW) | Location | Electricity Purchaser | PPA Expiry Year
Facility: Dickson Dam Hydro Facility Owner: Algonquin Power Operating Trust | 15 | Innisfail, Alberta | AESO | N/A
Facility: Tinker Hydro Facility Owner: Algonquin Tinker Gen Co. | 34 | Perth-Andover, New Brunswick | Algonquin Energy Services Inc. Town of Perth-Andover | Perth-Andover Contract through 2031
Facility: Bakersfield I Solar Facility Owner: Algonquin SKIC20 Solar, LLC | 20 | Kern County, California | Pacific Gas & Electric Company | 2035
Facility: Great Bay Solar Facility Owner: Great Bay Solar I, LLC | 75 | Somerset County, Maryland | Under Development - U.S. General Services Administration | 2028 (10 years after COD)
Facility: St. Leon Wind Facility Owner: St. Leon Wind Energy LP | 103.9 | St. Leon, Manitoba | Manitoba Hydro | 2026 + one 5 year extension
Facility: Amherst Island Wind Project Owner: Windlectric Inc. | 75 | Stella, Ontario | Under Development - IESO | 2038 (20 years after COD)
Facility: Blue Hill Wind Project Owner: Blue Hill Wind Energy Project Partnership | 177 | Lawtonia, Saskatchewan | Under Development - SaskPower | 2044/5 (25 years after COD)
Facility: Minonk Wind Facility Owner: Minonk Wind, LLC | 200 | Minonk, Illinois | PJM North Illinois | 2023 1
Facility: Senate Wind Facility Owner: Senate Wind, LLC | 150 | Graham, Texas | ERCOT North markets | 2027 1
Facility: Sandy Ridge Wind Facility Owner: Sandy Ridge Wind, LLC | 50 | Tyrone, Pennsylvania | PJM West | 2023 1

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Generating Facility/Owner | Generating Capacity (MW) | Location | Electricity Purchaser | PPA Expiry Year
Facility: Shady Oaks Wind Facility Owner: GSG 6, LLC | 109.5 | Lee County, Illinois | Commonwealth Edison | 2032
Facility: Odell Wind Facility Owner: Odell Wind Farm, LLC. | 200 | Cottonwood, Jackson, Martin and Watonwan Counties, Minnesota | Northern States Power | 2036
Facility: Deerfield Wind Facility Owner: Deerfield Wind Energy, LLC | 150 | Central Michigan | Wolverine Power Supply Co-operative | 2037

1 | The Corporation currently has hedge agreements in place in respect of each facility. See “Description of the Business – Liberty Power Group – Description of Operations – Wind Power Generating Facilities – Material Facilities”.

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SCHEDULE B
Selected Thermal – Biomass, Cogeneration, and Diesel Facilities

Generating Facility/Owner | Generating Capacity (MW) | Location | Electricity Purchaser | PPA Expiry Year | Lease Expiry Year
Facility: Sanger Facility Owner: Algonquin Power Sanger LLC | 56 | Sanger, California | Pacific Gas & Electric Company | 2021 | Owned
Facility: Windsor Locks Facility Owner: Algonquin Power Windsor Locks LLC | 71 | Windsor Locks, Connecticut | ISO New England Ahlstrom Corporation | 2027 | 2027

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SCHEDULE C
Selected Wastewater and Water Distribution Facilities

Utility | Owner | Location | Type of Utility | Rates 1
LPSCo System | Liberty Utilities (Litchfield Park Water & Sewer) Corp. | Litchfield, Park, Arizona | Wastewater Water Distribution | Pursuant to ACC docket 74437
Pine Bluff Water System | Liberty Utilities (Pine Bluff Water) Inc. | Pine Bluff, Arkansas | Water Distribution | Pursuant to APSC docket No. 14-020-U
Liberty Park Water System | Liberty Utilities (Park Water) Corp. | Downey, California | Water Distribution | Pursuant to CPUC decision 16-01-009
Apple Valley Water System | Liberty Utilities (Apple Valley Ranchos Water) Corp. | Apple Valley, California | Water Distribution | Pursuant to CPUC decision 15-11-030
Empire District Water System | The Empire District Electric Company | Joplin, Missouri | Distribution | MO – WR-2012-0300

1 | See www.libertyutilities.com for complete rate tariffs.

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SCHEDULE D
Selected Electrical Distribution Facilities

Utility | Owner | Location | Type of Utility | Rates 1
CalPeco Electric System | Liberty Utilities (CalPeco Electric) LLC | Lake Tahoe, California | Electricity Distribution | Rates pursuant to CPUC decision 16-12-024
Granite State Electric System | Liberty Utilities (Granite State Electric) Corp | Salem, New Hampshire | Electricity Distribution | Rates pursuant to NHPUC docket DE 13-063, Order 25,638 and docket DE 16-383, Order 26,005
Empire District Electric System | The Empire District Electric Company | Joplin, Missouri | Electricity Generation, Transmission & Distribution | MO - ER-2016-0023 AR - 13-111-U KS - 11-EPDE-856-RTS OK - PUD 201600468

1 | See www.libertyutilities.com for complete rate tariffs.

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SCHEDULE E
Selected Natural Gas Distribution Facilities

Utility | Owner | Location | Type of Utility | Rates 1
EnergyNorth Gas System | Liberty Utilities (EnergyNorth Natural Gas) Corp. | Londonderry, New Hampshire | Natural Gas Distribution | Rates pursuant to NHPUC docket DG 14-180, Order 25,797
Peach State Gas System | Liberty Utilities (Peach State Natural Gas) Corp. | Columbus, Gainesville, Georgia | Natural Gas Distribution | Rates pursuant to GPSC docket #34734 Document #166,984
New England Gas System | Liberty Utilities (New England Natural Gas Company) Corp. | Fall River, North Attleboro, Plainville, Westport, Swansea, Somerset, Massachusetts | Natural Gas Distribution | Rates pursuant to D.P.U 15-75
Midstates Gas System | Liberty Utilities (Midstates Natural Gas) Corp. | Salem, Virden, Vandalia, Xenia, Metropolis, Illinois Keokuk, Iowa Jackson, Sikeston, Butler, Kirksville, Hannibal, Missouri | Natural Gas Distribution | Rates pursuant to ICC decision IL-16-0401 Rates pursuant to IUB decision RPU-2016-0003 Rates pursuant to MOPSC decision GR-2014-0152
New Hampshire Gas System | Liberty Utilities (EnergyNorth Natural Gas) Corp. | Keene, New Hampshire | Propane Gas Distribution | Rates pursuant to NHPUC docket DG 09-038
Empire District Gas System | The Empire District Gas Company | Joplin, Missouri | Natural Gas Distribution | MO - GR-2009-0434

1 | See www.libertyutilities.com for complete rate tariffs.

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SCHEDULE F
ALGONQUIN POWER & UTILITIES CORP.
MANDATE OF THE AUDIT COMMITTEE
By appropriate resolution of the board of directors (the “Board”) of Algonquin Power & Utilities Corp., the Audit Committee (the “Committee”) has been established as a standing committee of the Board with the terms of reference set forth below. Unless the context requires otherwise, the term “Corporation” refers to Algonquin Power & Utilities Corp. and its subsidiaries.
1 PURPOSE
1.1 The Committee’s purpose is to:

(a) | assist the Board’s oversight of:

(i) | the integrity of the Corporation’s financial statements, Management’s Discussion and Analysis (“MD&A”) and other financial reporting;

(ii) | the Corporation’s compliance with legal and regulatory requirements;

(iii) | the external auditor’s qualifications, independence and performance;

(iv) | the performance of the Corporation’s internal audit function and internal auditor;

(v) | the communication among management of the Corporation and its subsidiary entities and the Corporation’s Chief Executive Officer and its Chief Financial Officer (collectively, “Management”), the external auditor, the internal auditor and the Board;

(vi) | the review and approval of any related party transactions; and

(vii) | any other matters as defined by the Board;

(b) | prepare and/or approve any report that is required by law or regulation to be included in any of the Corporation’s public disclosure documents relating to the Committee.

2 COMMITTEE MEMBERSHIP
2.1 Number of Members – The Committee shall consist of not fewer than three members.
2.2 Independence of Members – Each member of the Committee shall:

(a) | be a director of the Corporation;

(b) | not be an officer or employee of the Corporation or any of the Corporation’s subsidiary entities or affiliates; and

(c) | satisfy the independence requirements applicable to members of audit committees under each of the rules of National Instrument 52 110 – Audit Committees of the Canadian Securities Administrators (“NI 52 110”) and other applicable laws and regulations.

2.3 Financial Literacy – Each member of the Committee shall satisfy the financial literacy requirements applicable to members of audit committees under NI 52 110 and other applicable laws and regulations.
2.4 Chair – The Chair of the Committee shall be selected from among the members of the Committee.
2.5 Annual Appointment of Members – The Committee and its Chair shall be appointed annually by the Board and each member of the Committee shall serve at the pleasure of the Board until he or she resigns, is removed or ceases to be a director.
3 COMMITTEE MEETINGS
3.1 Time and Place of Meetings – The time and place of the meetings of the Committee and the calling of meetings and the procedure in all things at such meetings shall be determined by the Committee; provided, however, that the Committee shall meet at least quarterly and meetings of the Committee shall be convened whenever requested by the external auditors

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or any member of the Committee in accordance with the Canada Business Corporations Act. No business may be transacted by the Committee at a meeting unless a quorum of a majority of the members of the Committee is present. The Committee shall maintain minutes or other records of its meetings and activities.
3.2 In Camera Meetings – As part of each meeting of the Committee at which it approves, or if applicable, recommends that the Board approve, the annual audited financial statements of the Corporation or at which the Committee reviews the interim financial statements of the Corporation, and at such other times as the Committee deems appropriate, the Committee shall hold in camera meetings, and shall also meet separately with each of the persons set forth below to discuss and review specific issues as appropriate:

(a) | representatives of Management;

(b) | the external auditor; and

(c) | the internal audit personnel.

3.3 Attendance at Meetings – The external auditors are entitled to receive notice of every Committee meeting and to be heard and attend thereat at the Corporation’s expense. In addition, the Committee may invite to a meeting any officers or employees of the Corporation, legal counsel, advisor and other persons whose attendance it considers necessary or desirable in order to carry out its responsibilities.
4 COMMITTEE AUTHORITY AND RESOURCES
4.1 Direct Channels of Communication – The Committee shall have direct channels of communication with the Corporation’s internal and external auditors to discuss and review specific issues as appropriate.
4.2 Retaining and Compensating Advisors – The Committee, or any member of the Committee with the approval of the Committee, may retain at the expense of the Corporation such outside legal, accounting (other than the external auditor) or other advisors on such terms as the Committee may consider appropriate and shall not be required to obtain any other approval in order to retain or compensate any such advisors.
4.3 Funding – The Corporation shall provide for appropriate funding, as determined by the Committee, for payment of compensation of the external auditor and any advisor retained by the Committee under Section 4.2 of this mandate.
4.4 Investigations – The Committee shall have unrestricted access to the personnel and documents of the Corporation and the Corporation’s subsidiary entities and shall be provided with the resources necessary to carry out its responsibilities.
5 REMUNERATION OF COMMITTEE MEMBERS
5.1 Director Fees Only – No member of the Committee may accept, directly or indirectly, fees from the Corporation or any of its subsidiary entities other than remuneration for acting as a director or member of the Committee or any other committee of the Board.
5.2 Other Payments – For greater certainty, no member of the Committee shall accept any consulting, advisory or other compensatory fee from the Corporation. For purposes of Section 5.1, the indirect acceptance by a member of the Committee of any fee includes acceptance of a fee by an immediate family member or a partner, member or executive officer of, or a person who occupies a similar position with, an entity that provides accounting, consulting, legal, investment banking or financial advisory services to the Corporation or any of its subsidiaries, other than limited partners, non-managing members and those occupying similar positions who, in each case, have no active role in providing services to the entity.
6 DUTIES AND RESPONSIBILITIES OF THE COMMITTEE
6.1 Overview – The Committee’s principal responsibility is one of oversight. Management is responsible for preparing the Corporation’s financial statements and the external auditor is responsible for auditing those financial statements.
6.2 The Committee’s specific duties and responsibilities are as follows:

(a) | Financial and Related Information

(i) | Annual Financial Statements – The Committee shall review and discuss with Management and the external auditor the Corporation’s annual financial statements and related MD&A and if applicable, report thereon to the Board as a whole before they approve such statements and MD&A.

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(ii) | Interim Financial Statements – The Committee shall review and discuss with Management and the external auditor the Corporation’s interim financial statements and related MD&A and if applicable, report thereon to the Board as a whole before they approve such statements and MD&A.

(iii) | Prospectuses and Other Documents – The Committee shall review and discuss with Management and the external auditor the financial information, financial statements and related MD&A appearing in any prospectus, annual report, annual information form, management information circular or any other public disclosure document prior to its public release or filing and if applicable, report thereon to the Board as a whole.

(iv) | Accounting Treatment – Prior to the completion of the annual external audit, and at any other time deemed advisable by the Committee, the Committee shall review and discuss with Management and the external auditor (and shall arrange for the documentation of such discussions in a manner it deems appropriate) the quality and not just the acceptability of the Corporation’s accounting principles and financial statement presentation, including, without limitation, the following:

(A) | all critical accounting policies and practices to be used, including, without limitation, the reasons why certain estimates or policies are or are not considered critical and how current and anticipated future events impact those determinations and an assessment of Management’s disclosures along with any significant proposed modifications by the auditors that were not included;

(B) | all alternative treatments within generally accepted accounting principles for policies and practices related to material items that have been discussed with Management, including, without limitation, ramification of the use of such alternative disclosure and treatments, and the treatment preferred by the external auditor, which discussion should address recognition, measurement and disclosure consideration related to the accounting for specific transactions as well as general accounting policies. Communications regarding specific transactions should identify the underlying facts, financial statement accounts impacted and applicability of existing corporate accounting policies to the transaction. Communications regarding general accounting policies should focus on the initial selection of, and changes in, significant accounting policies, the impact of the Management’s judgments and accounting estimates and the external auditor’s judgments about the quality of the Corporation’s accounting principles. Communications regarding specific transactions and general accounting policies should include the range of alternatives available under generally accepted accounting principles discussed by Management and the auditors and the reasons for selecting the chosen treatment or policy. If the external auditor’s preferred accounting treatment or accounting policy is not selected, the reasons therefore should also be reported to the Committee;

(C) | other material written communications between the external auditor and Management, such as any management letter, schedule of unadjusted differences, listing of adjustments and reclassifications not recorded, management representation letter, report on observations and recommendations on internal controls, engagement letter and independence letter;

(D) | major issues regarding financial statement presentations;

(E) | any significant changes in the Corporation’s selection or application of accounting principles;

(F) | the effect of regulatory and accounting initiatives, as well as off balance sheet structures, on the financial statements of the Corporation; and

(G) | the adequacy of the Corporation’s internal controls and any special audit steps adopted in light of control deficiencies.

(v) | Disclosure of Other Financial Information – The Committee shall:

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(A) | review earnings releases, and review and discuss generally with Management, the type and presentation of information to be included in, all public disclosure by the Corporation containing audited, unaudited or forward-looking financial information in advance of its public release by the Corporation, including, without limitation, earnings guidance and financial information based on unreleased financial statements;

(B) | discuss generally with Management the type and presentation of information to be included in earnings and any other financial information given to analysts and rating agencies, if any; and

(C) | satisfy itself that adequate procedures are in place for the review of the Corporation’s disclosure of financial information extracted or derived from the Corporation’s financial statements, other than the Corporation’s financial statements, MD&A and earnings press releases, and shall periodically assess the adequacy of those procedures.

(b) | External Auditor

(i) | Authority with Respect to External Auditor – As a representative of the Corporation’s shareholders and as a committee of the Board, the Committee shall be directly responsible for the appointment, compensation, retention, termination and oversight of the work of the external auditor (including, without limitation, resolution of disagreements between Management and the auditor regarding financial reporting) for the purpose of preparing or issuing an audit report or performing other audit, review or attest services for the Corporation. In this capacity, the Committee shall have sole authority for recommending the person to be proposed to the Corporation’s shareholders for appointment as external auditor, for determining whether at any time the incumbent external auditor should be removed from office, and for determining the compensation of the external auditor. The Committee shall require the external auditor to confirm in an engagement letter to the Committee each year that the external auditor is accountable to the Board and the Committee as representatives of shareholders and that it will report directly to the Committee.

(ii) | Approval of Audit Plan – The Committee shall approve, prior to the external auditor’s audit, the external auditor’s audit plan (including, without limitation, staffing), the scope of the external auditor’s review and all related fees.

(iii) | Independence – The Committee shall satisfy itself as to the independence of the external auditor. As part of this process:

(A) | The Committee shall require the external auditor to submit on a periodic basis to the Committee a formal written statement confirming its independence under applicable laws and regulations and delineating all relationships between the auditor and the Corporation and the Committee shall actively engage in a dialogue with the external auditor with respect to any disclosed relationships or services that may impact the objectivity and independence of the external auditor and take, or, if applicable, recommend that the Board take, any action the Committee considers appropriate in response to such report to satisfy itself of the external auditor’s independence.

(B) | In accordance with applicable laws and regulations, the Committee shall pre-approve any non-audit services (including, without limitation, fees therefor) provided to the Corporation or its subsidiaries by the external auditor or any auditor of any such subsidiary and shall consider whether these services are compatible with the external auditor’s independence, including, without limitation, the nature and scope of the specific non-audit services to be performed and whether the audit process would require the external auditor to review any advice rendered by the external auditor in connection with the provision of non‑audit services. The Committee may delegate to one or more designated members of the Committee, such designated members not being members of management, the authority

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to approve additional non‑audit services that arise between Committee meetings, provided that such designated members report any such approvals to the Committee at the next scheduled meeting.

(C) | The Committee shall establish a policy setting out the restrictions on the Corporation’s subsidiary entities hiring partners, employees, former partners and former employees of the Corporation’s external auditor or former external auditor.

(iv) | Rotating of Auditor Partner – The Committee shall evaluate the performance of the external auditor and whether it is appropriate to adopt a policy of rotating lead or responsible partners of the external auditors.

(v) | Review of Audit Problems and Internal Audit – The Committee shall review with the external auditor:

(A) | any problems or difficulties the external auditor may have encountered, including, without limitation, any restrictions on the scope of activities or access to required information, and any disagreements with Management and any management letter provided by the auditor and the Corporation’s response to that letter;

(B) | any changes required in the planned scope of the internal audit; and

(C) | the internal audit department’s responsibilities, budget and staffing.

(vi) | Review of Proposed Audit and Accounting Changes – The Committee shall review major changes to the Corporation’s auditing and accounting principles and practices suggested by the external auditor.

(vii) | Regulatory Matters – The Committee shall discuss with the external auditor the matters required to be discussed by Section 5741 of the CICA Handbook – Assurance relating to the conduct of the audit.

(c) | Internal Audit Function – Controls

(i) | Regular Reporting – Internal audit personnel shall report regularly to the Committee.

(ii) | Oversight of Internal Controls – The Committee shall oversee Management’s design and implementation of and reporting on the Corporation’s internal controls and review the adequacy and effectiveness of Management’s financial information systems and internal controls. The Committee shall periodically review and approve the mandate, plan, budget and staffing of internal audit personnel. The Committee shall direct Management to make any changes it deems advisable in respect of the internal audit function.

(iii) | Review of Audit Problems – The Committee shall review with the internal audit personnel: any problem or difficulties the internal audit personnel may have encountered, including, without limitation, any restrictions on the scope of activities or access to required information, and any significant reports to Management prepared by the internal audit personnel and Management’s responses thereto.

(iv) | Review of Internal Audit Personnel – The Committee shall review the appointment, performance and replacement of the senior internal auditing personnel and the activities, organization structure and qualifications of the persons responsible for the internal audit function.

(d) | Risk Assessment and Risk Management

(i) | Risk Exposure – The Committee shall discuss with the external auditor, internal audit personnel and Management periodically the Corporation’s major financial risk exposures and the steps Management has taken to monitor and control such exposures.

(ii) | Investment Practices – The Committee shall review Management’s plans and strategies around investment practices, banking performance and treasury risk management.

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(iii) | Compliance with Covenants – The Committee shall review Management’s procedures to assess compliance by the Corporation with its loan covenants and restrictions, if any.

(e) | Legal Compliance

(i) | On at least a quarterly basis, the Committee shall review with the Corporation’s legal counsel, external auditor and Management any legal matters (including, without limitation, litigation, regulatory investigations and inquiries, changes to applicable laws and regulations, complaints or published reports) that could have a significant impact on the Corporation’s financial position, operating results or financial statements and the Corporation’s compliance with applicable laws and regulations.

(ii) | The Committee shall review and, if applicable, advise the Board with respect to the Corporation’s policies and procedures regarding compliance with applicable laws and regulations and shall notify Management and, if applicable, the Board, promptly after becoming aware of any material non-compliance by the Corporation with applicable laws and regulations.

(f) | Whistle Blowing – The Committee shall establish procedures for:

(i) | the receipt, retention and treatment of complaints received by the Corporation regarding accounting, internal accounting controls or auditing matters; and

(ii) | the confidential, anonymous submission by employees of the Corporation’s subsidiary entities of concerns regarding questionable accounting or auditing matters.

(g) | Review of the Management’s Certifications and Reports – The Committee shall review and discuss with Management all certifications of financial information, management reports on internal controls and all other management certifications and reports relating to the Corporation’s financial position or operations required to be filed or released under applicable laws and regulations prior to the filing or release of such certifications or reports.

(h) | Liaison – The Committee shall assess whether appropriate liaison and co–operation exist between the external auditor and internal audit personnel and provide a direct channel of communication between external and internal auditors and the Committee.

(i) | Public Reports – The Committee shall prepare and/or approve any report that is required by law or regulation to be included in any of the Corporation’s public disclosure documents relating to the Committee.

(j) | Other Matters – The Committee may, in addition to the foregoing, perform such other functions as may be necessary or appropriate for the performance of its oversight function.

7 REPORTING TO THE BOARD
7.1 Regular Reporting – If applicable, the Committee shall report to the Board following each meeting of the Committee and at such other times as the Committee may determine to be appropriate.
8 EVALUATION OF COMMITTEE PERFORMANCE
8.1 Performance Review – The Committee shall periodically assess its performance.
8.2 Amendments to Mandate

(a) | Review by Committee – The Committee shall periodically review and discuss the adequacy of this mandate and if applicable, recommend any proposed changes to the Board.

(b) | Review by Board – The Board will review and reassess the adequacy of the mandate periodically, as it considers appropriate.

9 LEGISLATIVE AND REGULATORY CHANGES
9.1 Compliance – It is the Board’s intention that this mandate shall reflect at all times all legislative and regulatory requirements applicable to the Committee. Accordingly, this mandate shall be deemed to have been updated to reflect any

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amendments to such legislative and regulatory requirements and shall be formally amended at least every fourteen months to reflect such amendments.
10 CURRENCY OF MANDATE
10.1 Currency of Mandate – This mandate was approved by the Board of Directors of Algonquin Power & Utilities Corp. effective March 1, 2018.

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SCHEDULE G
GLOSSARY OF TERMS
In this AIF, the following terms have the meanings set forth below, unless otherwise indicated:
“AAGES” has the meaning ascribed thereto under “General Development of the Business – Three Year History and Significant Acquisitions – Fiscal 2017 - Corporate”.
“AAGES Preferred Shares” has the meaning ascribed thereto under “Description of the Business – Portfolio Investments”.
“Abengoa” has the meaning ascribed thereto under “General Development of the Business – Three Year History and Significant Acquisitions – Fiscal 2017 - Corporate”.
“ACC” means the Arizona Corporation Commission.
“ADEQ” means Arizona Department of Environmental Quality.
“Adjusted EBITDA” has the meaning ascribed thereto under “Caution Concerning Forward-looking Statements and Forward-looking Information”.
“AESO” means Alberta Electric System Operator.
“AIF” means this annual information form.
“Amended and Restated Rights Plan” has the meaning ascribed thereto under “Description of Capital Structure – Shareholders’ Rights Plan”.
“Amherst Island Wind Project” has the meaning ascribed thereto under “Description of the Business – Liberty Power Group – Business Development – Current Development or Construction Projects”.
“APCI” means Algonquin Power Corporation Inc.
“APCo” has the meaning ascribed thereto under “Corporate Structure - Name, Address and Incorporation”.
“Apple Valley” has the meaning ascribed thereto under “Corporate Structure - Intercorporate Relationships”.
“Apple Valley Water System” means the Apple Valley Ranchos water facility in Apple Valley, California.
“APSC” means Arkansas Public Services Commission.
“APUC” has the meaning ascribed thereto under “Corporate Structure - Name, Address and Incorporation”.
“Atlantica” has the meaning ascribed thereto under “General Development of the Business – Three Year History and Significant Acquisitions – Fiscal 2017 - Corporate”.
“AY Shares” has the meaning ascribed thereto under “Description of the Business – Portfolio Investments”.
“Bakersfield I Solar Facility” means the 20 MW Bakersfield solar generating facility in California.
“Bakersfield II Solar Facility” means the 10 MW Bakersfield solar generating facility in California.

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“Blue Hill Wind Project” has the meaning ascribed thereto under “Description of the Business – Liberty Power Group – Business Development – Current Development or Construction Projects”.
“Board” means the Algonquin Power & Utilities Corp. Board of Directors.
“BRRBA” means base revenue requirement balancing account.
“CAISO” means California Independent System Operation.
“CalPeco Electric System” means the electricity distribution utility in the Lake Tahoe basin and surrounding areas.
“Carlyle” has the meaning ascribed thereto under the heading “Legal Proceedings and Regulatory Actions - Regulatory Actions – Mountain Water Condemnation”.
“CEQA” means California Environmental Quality Act.
“COD” means commercial operation date.
“Common Shares” means the common shares of Algonquin Power & Utilities Corp.
“Cornwall Solar Facility” means the solar generating facility in Cornwall, Ontario.
“Corporation” has the meaning ascribed thereto under “Corporate Structure - Name, Address and Incorporation”.
“CPCN” means Certificate of Public Convenience and Necessity.
“CPUC” means California Public Utilities Commission.
"DBRS" means the credit rating agency Dominion Bond Rating Service Limited.
“Debentures” has the meaning ascribed thereto under “General Development of the Business – Three Year History and Significant Acquisitions – Fiscal 2016 - Corporate”.
“Debenture Offering” has the meaning ascribed thereto under “General Development of the Business – Three Year History and Significant Acquisitions – Fiscal 2016 - Corporate”.
“Default Service” has the meaning ascribed thereto under “Description of the Business - Liberty Utilities Group - Electric Distribution Systems - Material Facilities”.
“Deerfield Wind Facility” means the Deerfield wind energy facility in Michigan.
“Dickson Dam Hydro Facility” means the Dickson hydroelectric generating facility in Alberta.
“ECAC” means energy cost adjustment clause.
“EDG” The Empire District Gas Company.
“Empire” has the meaning ascribed thereto under “Corporate Structure - Intercorporate Relationships”.
“Empire Acquisition” has the meaning ascribed thereto under "General Development of the Business – Three Year History and Significant Acquisitions – Fiscal 2016 - Corporate".

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“Empire Acquisition Facility” has the meaning ascribed thereto under “General Development of the Business – Three Year History and Significant Acquisitions – Fiscal 2016 - Corporate”.
“EnergyNorth Gas System” means a natural gas distribution utility in New Hampshire.
“ERCOT” means Electric Reliability Council of Texas.
“ERM” means enterprise risk management.
“EUA” means Electric Utilities Act (Alberta).
“EWGs” has the meaning ascribed thereto under “Description of the Business – Liberty Power Group - Regulatory Regimes-Power Generation - United States”.
“FERC” means the Federal Energy Regulatory Commission.
“FIT” means feed-in tariff.
“FPA” has the meaning ascribed thereto under “Description of the Business - Liberty Power Group - Regulatory Regimes-Power Generation - United States”.
“Full PTC Projects” has the meaning ascribed thereto under “General Development of the Business - Three Year History and Significant Acquisitions - Fiscal 2016 - Liberty Power Group Highlights”.
“GAAP” means Generally Accepted Accounting Principles.
“GAF” has the meaning ascribed thereto under “Description of the Business – Liberty Utilities Group – Description of Operations – Natural Gas Distribution Systems – Material Facilities”.
“GRAM” means the Georgia Rate Adjustment Mechanism.
“Great Bay Solar Project” means the Great Bay solar facility in Somerset County, Maryland.
“Granite State Electric System” means an electrical distribution utility in New Hampshire.
“Hydro-Québec” means Hydro-Québec Distribution.
“IESO” means Independent Electricity System Operator.
“ISO” means independent system operator.
“ISO-NE” means Independent System Operator New England.
“JPMVEC” has the meaning ascribed thereto under “Description of the Business – Liberty Power Group – Description of Operations – Wind Power Generating Facilities – Material Facilities”.
“KCC” means State Corporation Commission of the State of Kansas.
“Liberty Park Water” has the meaning ascribed thereto under “Corporate Structure - Intercorporate Relationships”.
“Liberty Park Water System” has the meaning ascribed thereto under “General Development of the Business - Three Year History and Significant Acquisitions - Fiscal 2016 - Liberty Utilities Group”.

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“Long Sault Hydro Facility” means the Long Sault rapids hydroelectric generating facility.
“LPSCo System” means the Litchfield Park water and wastewater system in Arizona.
“LU Canada” has the meaning ascribed thereto under “Corporate Structure - Intercorporate Relationships”.
“Luning Facility” has the meaning ascribed thereto under “General Development of the Business – Three Year History and Significant Acquisitions – Fiscal 2017 – Liberty Utilities Group”.
“Manitoba Hydro” means the Manitoba Hydro-Electric Board.
“MBR Authority” has the meaning ascribed thereto under “Description of the Business - Liberty Power Group - Regulatory Regimes-Power Generation - United States”.
“MD&A” has the meaning ascribed thereto under “Caution Concerning Forward-looking Statements and Forward-looking Information”.
“MDPU” means The Massachusetts Department of Public Utilities.
“Midstates Gas Systems” means natural gas distribution utility assets in Missouri, Iowa and Illinois.
“Minonk Wind Facility” means the Minonk wind energy facility in Illinois.
“MISO” means Midcontinent Independent System Operator, Inc.
“Moody’s” means Moody’s Investors Services, Inc.
“Morse Wind Facility” means the Morse wind facility in Saskatchewan.
“MPSC” means Missouri Public Services Commission.
“MW” means megawatt.
“MWh” means megawatt hours.
“NB Power” means New Brunswick Power Corporation.
“NBSO” means New Brunswick System Operator.
“Net Energy Sales” has the meaning ascribed thereto under “Caution Concerning Forward-looking Statements and Forward-looking Information”.
“Net Utility Sales” has the meaning ascribed thereto under “Caution Concerning Forward-looking Statements and Forward-looking Information”.
“New England Gas System” means natural gas distribution utility assets in Massachusetts.
“NHPUC” means the New Hampshire Public Utilities Commission.
“NERC” means the North American Electric Reliability Corporation.
“NV Energy” means NV Energy, Inc.

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“NYSE” means New York Stock Exchange.
“OATT” means open access transmission tariff.
“OCC” means Corporation Commission of Oklahoma.
“Odell Wind Facility” means the 200 MW Odell wind facility in Cottonwood, Jackson, Martina and Watonwan counties in Minnesota.
“OEB” means the Ontario Energy Board.
“OEFC” means Ontario Electric Financial Corporation.
“OPEB” has the meaning ascribed thereto under “Enterprise Risk Factors – Risk Factors Relating to Financing and Financial Reporting”.
“OPG” means Ontario Power Generation Inc.
“Peach State Gas System” means natural gas distribution utility assets in Georgia.
“PGA” means Purchased Gas Adjustment.
“PJM” means PJM Interconnection.
“PPA” means power purchase agreement.
“Primary Energy Production Hedge” has the meaning ascribed thereto under “Description of the Business – Liberty Power Group – Description of Operations – Wind Power Generating Facilities – Material Facilities”.
“PTC” has the meaning ascribed thereto under “General Development of the Business - Three Year History and Significant Acquisitions - Fiscal 2016 - Liberty Power Group”.
“PUHCA” has the meaning ascribed thereto under “Description of the Business - Liberty Power Group - Regulatory Regimes-Power Generation - United States”.
“QFs” has the meaning ascribed thereto under “Description of the Business - Liberty Power Group - Regulatory Regimes-Power Generation - United States”.
“REC” means renewable energy credits.
“Red Lily Wind Facility” has the meaning ascribed thereto under “General Development of the Business - Three Year History and Significant Acquisitions - Fiscal 2016 - Liberty Power Group”.
“Reinvestment Plan” has the meaning ascribed thereto under “General Development of the Business – Three Year History and Significant Acquisitions – Fiscal 2017 - Corporate”.
“RPS” means renewable portfolio standards.
“RTO” means regional transmission organization.
“S&P” means Standard & Poor’s Financial Services LLC.
“Saint-Damase Wind Facility” means the Saint-Damase wind facility.

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“Sandy Ridge Wind Facility” means the Sandy Ridge wind energy facility in Texas.
“Senate Wind Facility” means the Senate wind energy facility in Texas.
“Series A Shares” has the meaning ascribed thereto under “Dividends - Preferred Shares”.
“Series B Shares” has the meaning ascribed thereto under “Description of Capital Structure – Preferred Shares”.
“Series C Shares” has the meaning ascribed thereto under “Description of Capital Structure – Preferred Shares”.
“Series D Shares” has the meaning ascribed thereto under “Dividends - Preferred Shares”.
“Series E Shares” has the meaning ascribed thereto under “Description of Capital Structure – Preferred Shares”.
“Shady Oaks Wind Facility” means the Shady Oaks wind energy facility in Illinois.
“SLG” has the meaning ascribed thereto under “General Development of the Business – Three Year History and Significant Acquisitions – Fiscal 2017 – Liberty Utilities Group”.
“SPP” means Southwest Power Pool.
“SPP IM” has the meaning ascribed thereto under “Enterprise Risk Factors – Risk Factors Relating to Operations”.
“St. Leon II Wind Facility” means the 16.5 MW wind facility located at St. Leon, Manitoba.
“St. Leon LP” has the meaning ascribed thereto under “Corporate Structure - Intercorporate Relationships - Subsidiaries”.
“St. Leon Wind Facility” means the 104 MW wind facility located at St. Leon, Manitoba.
“SWRCB” means the Division of Drinking Water of the California State Water Resources Control Board.
“Tinker Hydro Facility” means the electric generating facility and transmission assets in New Brunswick.
“TSX” means the Toronto Stock Exchange.
“Val-Éo Wind Project” “has the meaning ascribed thereto under “Description of the Business – Liberty Power Group – Business Development – Current Development or Construction Projects”.
“Windsor Locks Facility” has the meaning ascribed thereto under the heading “Description of the Business - Liberty Power Group - Description of Operations - Thermal (Cogeneration) Electric Generating Facilities - Material Facilities”.