Exhibit

EX-99.3 4 a2016q4-exhibit993xmda.htm EXHIBIT 99.3 SUPPLEMENTARY MC Exhibit

Exhibit 99.3

Management Commentary

(All monetary amounts are in thousands of Canadian dollars, except per share amounts or where otherwise noted.)

Management of Algonquin Power & Utilities Corp. (“APUC” or the “Company”) has prepared the following to provide information to assist its shareholders’ understanding of the unaudited financial results for the three and twelve months ended December 31, 2016. The Management Commentary ("MC") should be read in conjunction with APUC’s unaudited supplementary financial information accompanying this MC. Additional information about APUC, including the most recent Annual Information Form (“AIF”) can be found on SEDAR at www.sedar.com and on the APUC website at www.AlgonquinPowerandUtilities.com. Capitalized terms used herein and not otherwise defined will have the meanings assigned to them in the Corporation's 2016 AIF.

This MC is based on information available to management as of March 2, 2017.

Caution Concerning Forward-looking Statements and non-GAAP Measures

Forward-looking Statements

Certain statements included herein contain forward-looking information within the meaning of certain securities laws. These statements reflect the views of APUC with respect to future events, based upon assumptions relating to, among others, the performance of APUC’s assets as well as the business, interest and exchange rates, commodity market prices, and the financial and regulatory climate in which it operates. These forward looking statements include, among others, statements with respect to the expected performance of APUC, its future plans and its dividends to shareholders. Statements containing expressions such as “anticipates”, “believes”, “continues”, “could”, “expect”, “estimates”, “intends”, “may”, “outlook”, “plans”, “project”, “strives”, “will”, and similar expressions generally constitute forward-looking statements.

Since forward-looking statements relate to future events and conditions, by their very nature they require APUC to make assumptions and involve inherent risks and uncertainties. APUC cautions that although it believes its assumptions are reasonable in the circumstances, these risks and uncertainties give rise to the possibility that actual results may differ materially from the expectations set out in the forward-looking statements. Material risk factors include the impact of movements in exchange rates and interest rates; the effects of changes in environmental and other laws and regulatory policy applicable to the energy and utilities sectors; decisions taken by regulators on monetary policy; and the state of the Canadian and the United States (“U.S.”) economies and accompanying business climate. APUC cautions that this list is not exhaustive, and other factors could adversely affect results. Given these risks, undue reliance should not be placed on these forward-looking statements. In addition, such statements are made based on information available and expectations as of the date of this MC and such expectations may change after this date. APUC reviews material forward-looking information it has presented, not less frequently than on a quarterly basis. APUC is not obligated to nor does it intend to update or revise any forward-looking statements, whether as a result of new information, future developments or otherwise, except as required by law.

Non-GAAP Financial Measures

The terms “Adjusted Net Earnings”, “Adjusted Earnings Before Interest, Taxes, Depreciation and Amortization” (“Adjusted EBITDA”), “Adjusted Funds from Operations”, "Net Energy Sales", "Net Utility Sales" and "Divisional Operating Profit" are used throughout this MC. The terms “Adjusted Net Earnings”, “Adjusted Funds from Operations”, "Adjusted EBITDA", "Net Energy Sales", "Net Utility Sales" and "Divisional Operating Profit" are not recognized measures under GAAP. There is no standardized measure of “Adjusted Net Earnings”, "Adjusted EBITDA", “Adjusted Funds from Operations”, "Net Energy Sales", "Net Utility Sales", and "Divisional Operating Profit"; consequently, APUC’s method of calculating these measures may differ from methods used by other companies and therefore may not be comparable to similar measures presented by other companies. A calculation and analysis of “Adjusted Net Earnings”, "Adjusted EBITDA", “Adjusted Funds from Operations”, "Net Energy Sales", "Net Utility Sales", and "Divisional Operating Profit" can be found throughout this MC.

Use of Non-GAAP Financial Measures

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 Company. 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.

Adjusted Net Earnings

Adjusted Net Earnings is a non-GAAP measure used by many investors to compare net earnings from operations without the effects of certain volatile primarily non-cash items that generally have no current economic impact or items such as acquisition expenses or litigation expenses that are viewed as not directly related to a company’s operating performance. APUC uses Adjusted Net Earnings to assess its performance without the effects of (as applicable): gains or losses on foreign exchange, foreign exchange forward contracts, interest rate swaps, acquisition costs, litigation expenses and write down of intangibles and property, plant and equipment, earnings or loss from discontinued operations and other typically non-recurring items as these are not reflective of the performance of the underlying business of APUC. APUC believes that analysis and presentation of net earnings or loss on this basis will enhance an investor’s understanding of the operating performance of its businesses. It is not intended to be representative of net earnings or loss determined in accordance with GAAP, which can be impacted positively or negatively by these items.

Adjusted Funds from Operations

Adjusted Funds from Operations is a non-GAAP measure used by investors to compare cash flows from operating activities without the effects of certain volatile items that generally have no current economic impact or items such as acquisition expenses that are viewed as not directly related to a company’s operating performance. APUC uses Adjusted Funds from Operations to assess its performance without the effects of (as applicable): changes in working capital balances, acquisition expenses, litigation expenses, cash provided by or used in discontinued operations and other typically non-recurring items affecting cash from operations as these are not reflective of the long-term performance of the underlying businesses of APUC. Where APUC manages the day to day operations of a facility and receives the majority of its economic benefits, the Adjusted Funds from Operations of the entire facility is included in calculating the measure. APUC believes that analysis and presentation of funds from operations on this basis will enhance an investor’s understanding of the operating performance of its businesses. It is not intended to be representative of cash flows from operating activities as determined in accordance with GAAP, which can be impacted positively or negatively by these items.

Net Energy Sales

Net Energy Sales is a non-GAAP measure used by investors to identify revenue after commodity costs used to generate revenue where such revenue generally increases or decreases in response to increases or decreases in the cost of the commodity used to produce that revenue. APUC uses Net Energy Sales to assess its revenues without the effects of fluctuating commodity costs as such costs are predominantly passed through either directly or indirectly in the rates that are charged to customers. APUC believes that analysis and presentation of Net Energy Sales on this basis will enhance an investor’s understanding of the revenue generation of its businesses. It is not intended to be representative of revenue as determined in accordance with GAAP.

Net Utility Sales

Net Utility Sales is a non-GAAP measure used by investors to identify utility revenue after commodity costs, either natural gas or electricity, where these commodity costs are generally included as a pass through in rates to its utility customers. APUC uses Net Utility Sales to assess its utility revenues without the effects of fluctuating commodity costs as such costs are predominantly passed through and paid for by utility customers. APUC believes that analysis and presentation of Net Utility Sales on this basis will enhance an investor’s understanding of the revenue generation of its utility businesses. It is not intended to be representative of revenue as determined in accordance with GAAP.

Divisional Operating Profit

Divisional Operating Profit is a non-GAAP measure. APUC uses Divisional Operating Profit to assess the operating performance of its business groups without the effects of (as applicable): depreciation and amortization expense, corporate administrative expenses, income tax expense or recoveries, acquisition costs, litigation expenses, interest expense, gain or loss on derivative financial instruments, write down of intangibles and property, plant and equipment, and gain or loss on foreign exchange, earnings or loss from discontinued operations and other typically non-recurring items. APUC adjusts for these factors as they may be non-cash, unusual in nature and are not factors used by management for evaluating the operating performance of the divisional units. Divisional Operating Profit is calculated inclusive of Hypothetical Liquidation at Book Value (“HLBV”) income, which represents the value of net tax attributes earned in the period from electricity generated by certain of its U.S. wind power and U.S. solar generation facilities. Where the Company manages the day to day operations of a facility and receives



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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 divisional operating performance. Divisional Operating Profit is not intended to be representative of cash provided by operating activities or results of operations determined in accordance with GAAP.

Capitalized terms used herein and not otherwise defined will have the meanings assigned to them in the Company's most recent AIF.

Overview and Business Strategy

APUC is incorporated under the Canada Business Corporations Act. APUC owns and operates a diversified portfolio of regulated and non-regulated generation, distribution, and transmission utility assets which 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 appreciation.

APUC’s current quarterly dividend to shareholders is U.S. $0.1165 per common share or U.S. $0.4659 per common share per annum. Based on exchange rates as at March 1, 2017, the quarterly dividend is equivalent to Cdn $0.1554 per common share or Cdn $0.6216 per common share per annum. APUC believes its annual dividend payout allows for both an immediate return on investment for shareholders and retention of sufficient cash within APUC to fund growth opportunities. Further increases in the level of dividends paid by APUC are at the discretion of the APUC Board of Directors (the “Board”), with dividend levels being reviewed periodically by the Board in the context of cash available for distribution and earnings together with an assessment of the growth prospects available to APUC. APUC strives to achieve its results in the context of a moderate risk profile consistent with top-quartile North American power and utility operations.

APUC's operations are organized across two primary North American business units consisting of: the Renewable Generation Group which owns and operates a diversified portfolio of non-regulated renewable and thermal electric generation utility assets; and the Liberty Utilities Group which owns and operates a portfolio of regulated electric, natural gas, water distribution and wastewater collection utility systems, and transmission operations.

Renewable Generation Group

The Renewable Generation 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 Renewable Generation Group seeks to deliver continuing growth through development of new greenfield power generation projects and accretive acquisitions of additional electrical energy generation facilities.

The Renewable Generation 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 88% of the electrical output from the hydroelectric, wind, and solar generating facilities is sold pursuant to long term contractual arrangements which have a production-weighted average remaining contract life of 16 years.

The Renewable Generation Group also has a portfolio of development projects that when constructed will add approximately 351 MW of generation capacity from wind and solar powered generating facilities that have a production-weighted average contract life of 22 years.

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 APUC. 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.

On January 1, 2017, Liberty Utilities Co., APUC's wholly-owned regulated utility business, completed the acquisition of The Empire District Electric Company ("Empire"). Empire is a vertically-integrated utility providing electric, natural gas and water service to approximately 218,000 customers in Missouri, Kansas, Oklahoma, and Arkansas.

Including Empire, the Liberty Utilities Group now serves approximately 783,000 customers.

The Liberty Utilities Group's regulated electrical distribution utility systems and related generation assets are located in the States of California and New Hampshire. With the addition of Empire, the service territory has expanded into Missouri, Kansas, Oklahoma and Arkansas. The Liberty Utilities Group now serves approximately 264,000 electric connections.

The Liberty Utilities Group's regulated natural gas distribution utility systems are located in the States of Georgia, Illinois, Iowa, Massachusetts, New Hampshire and Missouri. With the expanded Missouri service area, the Liberty Utilities Group now serves approximately 336,000 natural gas connections.



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The Liberty Utilities Group's regulated water distribution and wastewater collection utility systems are located in the States of Arizona, Arkansas, California, Illinois, Missouri, Montana, and Texas; together serving approximately 183,000 connections.

With the integration of Empire, the Liberty Utilities Group now operates a fleet of regulated generation assets with a net capacity of 1,374MW.



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Algonquin Power & Utilities Corp. - Management Commentary

2016 Major Highlights

Corporate Highlights

Completion of The Empire District Electric Company Acquisition

Subsequent to year end, on January 1, 2017, APUC's wholly-owned regulated utility business 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 that serves approximately 218,000 customers in Missouri, Kansas, Oklahoma, and Arkansas.

With the closing of the Acquisition, APUC has materially expanded its utility operations in the U.S.. APUC, through its 2,200 employees, now serves over 783,000 electric, gas, and water customers within its regulated utility business, and APUC's portfolio of power generating facilities now contains both regulated and non-regulated power facilities with a total capacity of over 2,500 MW.

APUC expects the Acquisition will be accretive to earnings per common share in the first full year following closing and approximately 7% - 9% accretive to APUC's net earnings per common share over a three-year period following closing, excluding one-time acquisition-related expenses, and assuming a stable currency exchange environment. APUC's increased contribution from regulated operations is also expected to further enhance the stability and predictability of the Company's Adjusted EBITDA, net earnings and quality of cash flows.

Annual dividend increased from U.S. $0.4235 to U.S. $0.4659 and

Declaration of Canadian Equivalent First Quarter Dividend of Cdn $0.1533 (U.S. $0.1165) per Common Share

APUC currently targets 10% annual growth in dividends payable to shareholders underpinned by increases in earnings and cashflow. Management believes that the increase in dividends is consistent with APUC’s stated strategy of delivering total shareholder return comprised of attractive current dividend yield and capital appreciation.

APUC completed the acquisition of Empire in the first quarter of 2017. In addition, it has completed construction of new electric generating stations and has a number of electric generating stations in construction and under development. Collectively these growth initiatives have continued to raise the growth profile of the Company. As a result, on January 16, 2017, the Board approved a dividend increase of U.S. $0.0424 per common share annually, bringing the total annual dividend to U.S. $0.4659 per common share, an increase of 10% over the previous annual dividend rate.

Concurrently, APUC declared a first quarter 2017 dividend of U.S. $0.1165 per common share payable on April 14, 2017 to shareholders of record on March 31, 2017. Based on the Bank of Canada noon exchange rate on the declaration date, the Canadian dollar equivalent for the first quarter 2017 dividend is set at Cdn $0.1533 per common share.

The previous four quarter equivalent Canadian dollar dividends per common share have been as follows:



	Q2 2016	Q3 2016	Q4 2016	Q1 2017	Total
U.S. dollar dividend	$0.1059	$0.1059	$0.1059	$0.1165	$0.4342
Canadian dollar equivalent	$0.1361	$0.1377	$0.1427	$0.1533	$0.5698

Strong Year of Operating Results

APUC recorded a strong twelve months of operations results relative to the same period last year.



(all dollar amounts in $ millions except per share information)	Twelve Months Ended December 31
	2016	2015	Change
Net earnings attributable to shareholders	$130.9	$117.5	11%
Adjusted Net Earnings	$161.6	$121.5	33%
Adjusted EBITDA	$476.9	$375.4	27%
Net earnings per common share	$0.44	$0.42	5%
Adjusted Net Earnings per common share	$0.57	$0.46	24%

Completion of Financing Related to the Acquisition

$1.15 Billion Bought Deal Offering of Convertible Unsecured Subordinated Debentures Represented by Instalment Receipts

In the first quarter of 2016, in connection with the Acquisition, APUC and its direct wholly-owned subsidiary, Liberty Utilities (Canada) Corp., entered into an agreement with a syndicate of underwriters under which the underwriters agreed to buy, on



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a bought deal basis, $1.15 billion aggregate principal amount of 5.00% convertible unsecured subordinated debentures ("Debentures") of APUC (the "Debenture Offering").

Following the closing of the Acquisition, the final instalment date was established as February 2, 2017 at which time APUC received the final instalment payment. To date, approximately 99.1% of the Debentures have been converted into common shares of APUC, with APUC issuing approximately 107,517,895 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 Acquisition ("Acquisition Facility").

U.S. $750 Million Private Placement Offering

On March 1, 2017, Liberty Utilities Group's financing entity entered into an agreement to issue U.S. $750 million of senior unsecured private placement notes to 29 institutional investors in the U.S. and Canada. The notes are of varying maturities from 3 to 30 years with a weighted average life of approximately 15 years and a weighted average coupon of 3.6% after considering the effects of interest rate hedges entered into in 2016. The closing of the offering is scheduled to occur on March 24, 2017, with the proceeds to be used to repay the balance of the Acquisition Facility and other existing indebtedness.

See also Empire District Electric Company Acquisition in the Regulatory Proceedings of the Liberty Utilities Group

Dual Listing of APUC Common Shares on the New York Stock Exchange

During the fourth quarter, APUC received approval to list its common shares for trading on the New York Stock Exchange ("NYSE"), and trading commenced on November 29, 2016, under the ticker symbol "AQN". The Company has been a U.S. Securities and Exchange Commission (“SEC”) registrant since 2009 and operates primarily in the United States. APUC shares continue to be listed on the Toronto Stock Exchange also under the ticker symbol "AQN".

U.S. $235 Million Corporate Term Credit Facility

On January 4, 2016, the Company entered into a U.S. $235.0 million term credit facility ("Corporate Term Facility") with two U.S. banks. The proceeds of the term credit facility provide the company with additional liquidity for general corporate purposes and acquisitions. The facility matures on July 5, 2018.

Renewable Generation Group Highlights

Acquisition of 75% interest in the Red Lily I Partnership

Effective April 12, 2016, APUC, through its subsidiary, exercised its option to subscribe for a 75% equity interest in the Red Lily I Partnership, a 26.4 MW wind energy facility (the "Red Lily Wind Facility") located in southeastern Saskatchewan for which the Renewable Generation Group provides operation and supervisory services. The equity interest was obtained in exchange for the outstanding amounts on two subordinated loans previously advanced by a subsidiary of the Company. Accordingly, effective as of the exercise date, the financial results of the Red Lily Wind Facility are reported as part of the consolidated operations of APUC.

Completion of the Odell Wind Project

On July 29, 2016, the Odell Wind Facility achieved commercial operation ("COD"). The project consists of a 200 MW wind generating facility located in Cottonwood, Jackson, Martin, and Watonwan counties in Minnesota. On August 5, 2016, tax equity financing of approximately U.S. $180 million was completed. The Odell Wind Facility is the Renewable Generation Group's ninth wind generating facility and consists of 100 Vestas V110-2.0 wind turbines. The facility is expected to generate 831.8 GW-hrs annually. The project has a 20 year power purchase agreement ("PPA") with Northern States Power Company, a subsidiary of Xcel Energy Inc., which is a diversified utility operating in the Midwest U.S..

On September 15, 2016, the Company acquired the remaining 50% interest in Odell SponsorCo LLC for U.S $26.5 million and now controls the project.

Completion of the Deerfield Wind Project

Subsequent to year end, on February 21, 2017, the Deerfield Wind Facility achieved COD. The project consists of a 150 MW wind generating facility located in central Michigan. The Deerfield Wind Facility is the Renewable Generation Group's tenth wind generating facility and consists of 44 Vestas V110-2.0 wind turbines and 28 Vestas V110-2.2 turbines and is estimated to generate 555.2 GW-hrs annually. The project has a 20 year PPA with a local electric distribution utility serving approximately 260,000 customers in Michigan.

Completion of the Bakersfield II Solar Project

Subsequent to year end, on January 11, 2017, the Renewable Generation Group achieved COD on the 10 MWac solar generating facility located in Kern County, California (the "Bakersfield II Solar Facility"). On February 28, 2017, tax equity financing of approximately U.S. $12.2 million was completed. The Bakersfield II Solar Facility is the Renewable Generation Group's third solar generating facility and is comprised of approximately 38,640 solar panels located on 64 acres of land. The project is expected to generate 24.2 GW-hrs of energy annually. The project has a 20 year PPA with a large investment grade electric utility in California.



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Issuance of $300 million Senior Unsecured Debentures

Subsequent to year end, on January 17, 2017 the Renewable Generation Group issued $300.0 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 Renewable Generation 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 have been used to partially finance the Odell Wind, Deerfield Wind and Bakersfield II Solar projects.

Purchase of Turbines to Safe Harbor Production Tax Credit Rate

At the end of 2016, the Renewable Generation Group purchased approximately $75 million of turbine components ("Safe Harbor Turbines") 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 (“IRS”) 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 Renewable Generation Group is currently evaluating projects to maximize the value of this equipment.

Liberty Utilities Group Highlights

Acquisition of the 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 "Park Water System"). The acquisition of the Park Water System was originally announced in September 2014. The Park Water System owns and operates three regulated water utilities engaged in the production, treatment, storage, distribution, and sale of water in Southern California and western Montana. The three utilities collectively serve approximately 74,000 customer connections and have more than 1,000 miles of distribution mains.

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. This acquisition maintains APUC's strategic business mix and further enhances its investment grade consolidated capital structure.

The water utility located in western Montana is currently the subject of a condemnation proceeding by the city of Missoula. It is not known when the condemnation proceeding will conclude or whether the city of Missoula will ultimately take possession of the western Montana assets. (See "Regulatory Risk Section: Condemnation Expropriation Proceedings" for further discussion.)

Completion of the Luning Solar Project.

Subsequent to year end, on February 15, 2017, the Liberty Utilities Group obtained control of a 50 MW solar generating facility located in Mineral County, Nevada for approximately U.S. $110.9 million. The facility is comprised of approximately 204,784 solar panels located on 584 acres of land. The project is expected to generate 144.6 GW-hrs of energy annually. On February 17, 2017, tax equity financing of approximately U.S. $39.0 million was completed. The net capital cost of the project will be included in the rate base of the CalPeco Electric System as energy produced from the project will be consumed by the utility's customers.

Successful Rate Case Outcomes

A core strategy of the Liberty Utilities Group is to ensure an appropriate return is earned on the rate base at its various utility systems. During 2016, the Liberty Utilities Group successfully completed several rate cases representing a cumulative annualized revenue increase of approximately U.S. $21.4 million. The Liberty Utilities Group has pending rate case filings in progress that represent an increase in rates in the amount of U.S. $14.1 million which are expected to be completed in 2017.

Completion of Phase I of the North Lake Tahoe Transmission System Upgrades

During 2016, the Liberty Utilities Group completed the rebuild of the 10 mile Northstar to Kings Beach, California transmission line for approximately U.S. $21.5 million. The rebuild involved an upgrade to 120 kv and will improve the reliability of the transmission system. The project is being completed in three phases and the total capital cost of the project will be included in the rate base of the utility. The second phase will result in an upgrade to substations and is expected to be in service in 2017.



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Algonquin Power & Utilities Corp. - Management Commentary

2016 Fourth Quarter Results From Operations



Key Financial Information	Three Months Ended December 31
(all dollar amounts in $ millions except per share information)	2016		2015
Revenue	$	310.2	$	260.3
Net earnings attributable to shareholders from continuing operations	46.3		38.1
Net earnings attributable to shareholders	46.3		38.0
Cash provided by operating activities	121.3		94.3
Adjusted Net Earnings¹	51.4		39.7
Adjusted EBITDA¹	138.3		109.6
Adjusted Funds from Operations¹	95.8		77.2
Dividends declared to common shareholders	39.2		34.0
Weighted average number of common shares outstanding	273,952,963		258,048,584
Per share
Basic net earnings/(loss) from continuing operations	$	0.16	$	0.14
Basic net earnings/(loss)	$	0.16	$	0.14
Diluted net earnings/(loss)	$	0.16	$	0.14
Adjusted Net Earnings^1,2	$	0.18	$	0.15
Dividends declared to common shareholders	$	0.14	$	0.13



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

For the three months ended December 31, 2016, APUC experienced an average U.S. exchange rate of approximately $1.3343 as compared to $1.3351 in the same period in 2015. As such, any quarter over quarter variance in revenue or expenses, in local currency, at any of APUC’s U.S. entities is affected by a change in the average exchange rate upon conversion to APUC’s reporting currency.

For the three months ended December 31, 2016, APUC reported total revenue of $310.2 million as compared to $260.3 million during the same period in 2015, an increase of $49.9 million. The major factors resulting in the increase in APUC revenue in the three months ended December 31, 2016 as compared to the corresponding period in 2015 are set out as follows:



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(all dollar amounts in $ millions)	Three Months Ended December 31
Comparative Prior Period Revenue	$	260.3
RENEWABLE GENERATION GROUP
Existing Facilities
Hydro: Increase due to higher pricing recognized for certain Hydro-Quebec PPAs, offset by a decline in retail volumes and market pricing in the Maritime region.	—
Wind Canada: Increase due to higher production at St. Leon and Morse Wind Facilities resulting from strong wind resources, partially offset by the expiry of the Wind Power Production Incentive ("WPPI").	1.5
Wind U.S.: Decrease primarily due to lower market prices and production volumes.	(3.4		)
Solar Canada: Decrease due to lower production at the Cornwall solar facility resulting primarily from lower realized irradiance.	(0.2		)
Solar U.S.: Increase due to greater availability at the Bakersfield I Solar Facility resulting from unscheduled maintenance that occurred in the prior year.	0.1
Thermal: Increase primarily due to higher REC revenue and production at the Windsor Locks Thermal Facility, partially offset by lower production and pricing at the Sanger Thermal Facility.	0.5
Other	(0.3		)
	(1.8		)
New Facilities
Wind U.S.: Acquisition of the Odell Wind Facility.	5.7
	5.7
Foreign Exchange	—

LIBERTY UTILITIES GROUP
Existing Facilities
Electricity: Decrease primarily due to reduced cost of energy which was partially offset by increased residential demand at the Granite State Electric System.	(3.7		)
Gas: Increase primarily due to higher demand at the EnergyNorth and New England Gas Systems, and higher transportation revenues.	8.7
Water: Increase primarily due to higher consumption at the LPSCo and Bella Vista Water Systems.	0.4
Other: Increase primarily due to higher billings for contracted services.	5.9
	11.3
New Facilities
Water: Acquisition of the Park Water System.	21.0
	21.0
Rate Cases
Electricity: Implementation of new rates at the CalPeco Electric System retroactive to January 1, 2016.	11.9
Gas: Implementation of new rates at the Peach State and New England Gas Systems.	1.8
Water: Implementation of new rates at the Black Mountain Waste Water System and the Bella Vista and Rio Rico Water Systems.	0.6
	14.3
Foreign Exchange	(0.6		)
Current Period Revenue	$	310.2

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

For the three months ended December 31, 2016, net earnings attributable to shareholders totaled $46.3 million as compared to $38.0 million during the same period in 2015, an increase of $8.3 million or 21.8%. The increase was due to a $25.5 million increase in earnings from operating facilities, $1.4 million increase in interest, dividend, equity and other income, $1.9 million decrease in losses on long lived assets, $12.9 million increase in gains from derivative instruments, $0.3 million decrease in income tax expense (tax explanations are discussed in APUC: Corporate and Other Expenses), $0.1 million decrease in loss on discontinued operations, and $3.5 million increase in losses attributable to non-controlling interests. These items were partially offset by a $0.5 million increase in administration charges, $10.6 million increase in depreciation and amortization expenses, $1.0 million decrease in foreign exchange gain, $21.3 million increase in interest expense, $2.1 million decrease in other gains, and $1.8 million increase in acquisition costs as compared to the same period in 2015.



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Algonquin Power & Utilities Corp. - Management Commentary

During the three months ended December 31, 2016, cash provided by operating activities totaled $121.3 million as compared to cash provided by operating activities of $94.3 million during the same period in 2015. During the three months ended December 31, 2016, Adjusted Funds from Operations totaled $95.8 million compared to Adjusted Funds from Operations of $77.2 million during the same period in 2015. The change in Adjusted Funds from Operations in the three months ended December 31, 2016 is primarily due to increased earnings from operations as compared to the same period in 2015.

Adjusted EBITDA in the three months ended December 31, 2016 totaled $138.3 million as compared to $109.6 million during the same period in 2015, an increase of $28.7 million or 26.2%. A more detailed analysis of these factors is presented within the reconciliation of Adjusted EBITDA to net earnings set out below (see Non-GAAP Performance Measures).

2016 Annual Results From Operations



Key Financial Information	Twelve Months Ended December 31
(all dollar amounts in $ millions except per share information)	2016		2015		2014
Revenue	$	1,096.0	$	1,027.9	$	941.6
Net earnings attributable to shareholders from continuing operations	130.9		118.5		77.8
Net earnings attributable to shareholders	130.9		117.5		75.7
Cash provided by operating activities	287.3		261.9		192.7
Adjusted Net Earnings¹	161.6		121.5		88.2
Adjusted EBITDA¹	476.9		375.4		290.5
Adjusted Funds from Operations¹	355.8		287.4		206.5
Dividends declared to common shareholders	149.2		124.8		82.9
Weighted average number of common shares outstanding	271,832,430		253,172,088		213,953,870
Per share
Basic net earnings from continuing operations	$	0.44	$	0.43	$	0.32
Basic net earnings	$	0.44	$	0.42	$	0.31
Diluted net earnings	$	0.44	$	0.42	$	0.31
Adjusted Net Earnings^1,2	$	0.57	$	0.46	$	0.37
Dividends declared to common shareholders	$	0.55	$	0.49	$	0.37
Total assets	8,249.5		4,991.7		4,102.8
Long term debt³	4,272.0		1,486.8		1,271.7



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

For the twelve months ended December 31, 2016, APUC experienced an average U.S. exchange rate of approximately $1.3253 as compared to $1.2786 in the same period in 2015. As such, any year over year variance in revenue or expenses, in local currency, at any of APUC’s U.S. entities is affected by a change in the average exchange rate upon conversion to APUC’s reporting currency.

For the twelve months ended December 31, 2016, APUC reported total revenue of $1,096.0 million as compared to $1,027.9 million during the same period in 2015, an increase of $68.1 million or 6.6%. The major factors resulting in the increase in APUC revenue for the twelve months ended December 31, 2016 as compared to the corresponding period in 2015 are set out as follows:



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Algonquin Power & Utilities Corp. - Management Commentary



(all dollar amounts in $ millions)	Twelve Months Ended December 31
Comparative Prior Period Revenue	$	1,027.9
RENEWABLE GENERATION GROUP
Existing Facilities
Hydro: Increase due to the recognition of rates from the Global Adjustment from Ontario Energy Financial Corporation ("OEFC"), improved hydrology during the year in the Quebec and Maritime regions and higher rates contained in new PPAs in the Quebec region.	10.0
Wind Canada: Decrease primarily due to expiry of the Canadian Federal Wind Power Production Incentive ("WPPI").	(0.7		)
Wind U.S.: Decrease largely due to lower production at Minonk and Shady Oaks.	(3.4		)
Solar Canada: Increase primarily due to increased production at the Cornwall Solar Facility due to higher irradiance as compared to the prior year.	0.1
Thermal: Decrease primarily due to lower gas prices which is a pass-through to customers as well as reduced demand for steam.	(3.3		)
Other	(1.2		)
	1.5
New Facilities
Wind Canada: The Morse Wind Facility which achieved COD in April 2015.	4.1
Wind U.S.: Acquisition of the Odell Wind Facility.	7.0
Solar U.S.: The Bakersfield I Solar Facility achieved COD in April 2015 and experienced greater availability in the current year due to unscheduled maintenance that occurred in the prior year.	2.3
	13.4
Foreign Exchange	6.2

LIBERTY UTILITIES GROUP
Existing Facilities
Electricity: Decrease due to reduced cost of energy at the Granite State Electric System which is a direct pass-through to customers.	(17.9		)
Gas: Decrease due to reduced cost of gas and lower demand due to warmer winter weather experienced at the EnergyNorth, Peach State and Midstates and New England Gas systems.	(95.1		)
Water: Increase is primarily due to higher consumption at the LPSCo and Bella Vista Water Systems.	3.1
Other: Decrease primarily due to lower revenues for contracted services and the sale of the water heater rental business in the New England Gas System.	(2.8		)
	(112.7		)
New Facilities
Water: Acquisition of the Park Water System.	96.7
	96.7
Rate Cases
Electricity: Implementation of new rates at the CalPeco Electric system retroactive to January 1, 2016 and interim rates at the Granite State Electric System.	12.7
Gas: Implementation of new rates at the EnergyNorth, Peach State, Illinois and New England Gas Systems.	10.7
Water: Implementation of new rates at the Pine Bluff, Rio Rico, Bella Vista water systems and the Black Mountain waste water system.	0.8
	24.2
Foreign Exchange	38.8
Current Period Revenue	$	1,096.0

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

For the twelve months ended December 31, 2016, net earnings attributable to shareholders totaled $130.9 million as compared to $117.5 million during the same period in 2015, an increase of $13.4 million. The increase was due to a $95.9 million increase in earnings from operating facilities, $1.5 million increase in interest, dividend, equity and other income, $3.5 million increase in Other Gains, $6.2 million decrease in losses on long lived assets, $13.7 million increase on gains from



	11
Algonquin Power & Utilities Corp. - Management Commentary

derivative instruments, $6.6 million decrease in income tax expense (tax explanations are discussed in APUC: Corporate and Other Expenses), $1.0 million decrease in loss on discontinued operations, and $6.6 million increase in losses attributable to non-controlling interests. These items were partially offset by $37.1 million increase in depreciation and amortization expenses, $6.5 million increase in administration charges, $2.2 million decrease in foreign exchange gains, $65.6 million increase in interest expense and $10.2 million increase in acquisition costs as compared to the same period in 2015.

During the twelve months ended December 31, 2016, cash provided by operating activities totaled $287.3 million as compared to cash provided by operating activities of $261.9 million during the same period in 2015. During the twelve months ended December 31, 2016, Adjusted Funds from Operations, a non-GAAP measure, totaled $355.8 million as compared to Adjusted Funds from Operations of $287.4 million the same period in 2015, an increase of $68.4 million.

Adjusted EBITDA in the twelve months ended December 31, 2016 totaled $476.9 million as compared to $375.4 million during the same period in 2015, an increase of $101.5 million or 27.0%. A detailed analysis of this variance is presented within the reconciliation of Adjusted EBITDA to net earnings set out below (see Non-GAAP Performance Measures).

2016 Adjusted EBITDA Summary

Adjusted EBITDA (see Non-GAAP Performance Measures) in the three months ended December 31, 2016 totaled $138.3 million as compared to $109.6 million during the same period in 2015, an increase of $28.7 million or 26.2%. Adjusted EBITDA in the twelve months ended December 31, 2016 totaled $476.9 million as compared to $375.4 million during the same period in 2015, an increase of $101.5 million or 27.0%. The breakdown of Adjusted EBITDA by the company's main operating segments and a summary of changes are shown below.



Adjusted EBITDA by business units	Three Months Ended December 31						Twelve Months Ended December 31
(all dollar amounts in $ millions)	2016			2015			2016			2015
Renewable Generation Group Operating Profit	$	61.9		$	62.0		$	217.3		$	188.8
Liberty Utilities Group Operating Profit	87.1			59.2			302.4			224.1
Administrative Expenses	(13.1		)	(12.6		)	(46.3		)	(39.8		)
Other Income & Expenses	2.4			1.0			3.5			2.3
Total Algonquin Power & Utilities Adjusted EBITDA	$	138.3		$	109.6		$	476.9		$	375.4
Change in Adjusted EBITDA ($)	$	28.7					$	101.5
Change in Adjusted EBITDA (%)	26.2		%				27.0		%



Change in Adjusted EBITDA	Three Months Ended December 31, 2016
(all dollar amounts in $ millions)	Generation			Utilities			Corporate			Total
Prior period balances	$	62.0		$	59.2		$	(11.6	)	$	109.6
Existing Facilities	(5.1		)	6.2			1.5			2.6
New Facilities	5.4			7.7			—			13.1
Rate Cases	—			14.3			—			14.3
Foreign Exchange Impact	(0.4		)	(0.3		)	—			(0.7		)
Administrative Expenses	—			—			(0.6		)	(0.6		)
Total change during the period	$	(0.1	)	$	27.9		$	0.9		$	28.7
Current period balances	$	61.9		$	87.1		$	(10.7	)	$	138.3



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Algonquin Power & Utilities Corp. - Management Commentary



Change in Adjusted EBITDA	Twelve Months Ended December 31, 2016
(all dollar amounts in $ millions)	Generation		Utilities			Corporate			Total
Prior period balances	$	188.8	$	224.1		$	(37.5	)	$	375.4
Existing Facilities	8.9		(1.4		)	1.2			8.7
New Facilities	15.9		45.5			—			61.4
Rate Cases	—		24.2			—			24.2
Foreign Exchange Impact	3.7		10.0			—			13.7
Administration Expenses	—		—			(6.5		)	(6.5		)
Total change during the period	$	28.5	$	78.3		$	(5.3	)	$	101.5
Current period balances	$	217.3	$	302.4		$	(42.8	)	$	476.9

RENEWABLE GENERATION GROUP



2016 Electricity Generation Performance
	Long Term Average Resource	Three Months Ended December 31		Long Term Average Resource	Twelve Months Ended December 31
(Performance in GW-hrs sold)	Long Term Average Resource	2016	2015	Long Term Average Resource	2016	2015
Hydro Facilities:
Maritime Region	37.6	21.9	40.4	148.2	144.1	141.8
Quebec Region¹	72.6	64.0	72.8	273.9	267.5	260.9
Ontario Region	31.9	28.6	34.3	133.7	126.8	140.7
Western Region	12.6	18.1	13.6	65.0	66.1	56.2
	154.7	132.6	161.1	620.8	604.5	599.6
Wind Facilities:
St. Damase²	22.7	20.4	20.7	76.9	74.4	73.4
St. Leon	121.4	130.8	106.1	430.2	417.3	408.7
Red Lily³	24.1	25.4	20.7	88.5	82.6	78.8
Morse⁴	30.5	27.7	24.0	108.8	94.8	61.3
Sandy Ridge	43.6	51.8	43.7	158.3	155.8	150.0
Minonk	189.7	184.9	214.6	673.7	635.8	639.3
Senate	140.0	136.7	134.7	520.4	504.4	467.6
Shady Oaks	100.5	104.4	114.5	355.6	323.9	342.6
Odell⁵	238.1	211.2	—	348.8	297.7	—
	910.6	893.3	679.0	2,761.2	2,586.7	2,221.7
Solar Facilities:
Cornwall	2.2	1.9	2.3	14.7	15.6	15.2
Bakersfield I⁶	8.9	7.4	6.4	52.8	45.9	32.7
	11.1	9.3	8.7	67.5	61.5	47.9
Renewable Energy Performance	1,076.4	1,035.2	848.8	3,449.5	3,252.7	2,869.2

Thermal Facilities:
Windsor Locks	N/A⁷	30.9	25.5	N/A⁷	131.0	113.7
Sanger	N/A⁷	28.8	32.4	N/A⁷	118.7	129.8
		59.7	57.9		249.7	243.5
Total Performance		1,094.9	906.7		3,502.4	3,112.7



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Algonquin Power & Utilities Corp. - Management Commentary



1	The Renewable Generation Group's 4.8 MW Donnacona Hydro Facility went offline in May 2015. Reconstruction of the Donnacona Dam has advanced to a stage where limited generation is occurring, and completion is expected in late second quarter of 2017.
2	The quarterly timing of the long term average resource for St. Damase has been adjusted based on the first full year of operation. The annual value is unchanged.
3	Effective April 12, 2016, APUC, through its subsidiary, exercised its option and acquired a 75% equity interest in the Red Lily Wind Facility. For financial accounting purposes, APUC's majority interest in the Red Lily Wind Facility will be accounted for using the equity method. The production figures represent full energy produced by the facility.
4	The Morse Wind Facility achieved COD on April 22, 2015.
5	The Odell Wind Facility achieved COD on July 29, 2016 and was treated as an equity investment until September 15, 2016 at which time the Company acquired the remaining 50% ownership in the facility. The LTAR and production noted above represents all production from the date of COD.
6	The Bakersfield I Solar Facility achieved COD on April 14, 2015 in accordance with the terms of the PPA.
7	Natural gas fired co-generation facility.

2016 Fourth Quarter Generation Performance

For the three months ended December 31, 2016, the Renewable Generation Group generated 1,094.9 GW-hrs of electricity as compared to 906.7 GW-hrs during the same period of 2015.

For the three months ended December 31, 2016, the hydro facilities generated 132.6 GW-hrs of electricity as compared to 161.1 GW-hrs produced in the same period in 2015, a decrease of 17.7%. Electricity generated represented 85.7% of long-term average resources ("LTAR") as compared to 104.1% during the same period in 2015. During the quarter, increased generation in the Western region partly offsets declines in the Maritimes, Quebec and Ontario.

For the three months ended December 31, 2016, the wind facilities produced 893.3 GW-hrs of electricity as compared to 679.0 GW-hrs produced in the same period in 2015, an increase of 31.6%. The higher generation was primarily due to the first full quarter of production at the Odell Wind Facility (which achieved COD on July 29, 2016). This was partly offset by lower production at the Minonk and Shady Oaks Wind Facilities. During the three months ended December 31, 2016, the wind facilities (excluding the Odell Wind Facility) generated electricity equal to 101.3% of LTAR as compared to 100.9% during the same period in 2015.

For the three months ended December 31, 2016, the solar facilities generated 9.3 GW-hrs of electricity as compared to 8.7 GW-hrs of electricity in the same period in 2015, an increase of 6.9%. The increase in production is largely attributable to the Bakersfield I Solar Facility which was negatively impacted by unscheduled maintenance during the same period in 2015. Cornwall's production was 13.6% below its LTAR as compared to 4.5% above its LTAR in the same period in 2015.

For the three months ended December 31, 2016, the thermal facilities generated 59.7 GW-hrs of electricity as compared to 57.9 GW-hrs of electricity during the same period in 2015. During the same period, the Windsor Locks Thermal Facility generated 129.3 billion lbs of steam as compared to 155.0 billion lbs of steam during the same period in 2015.

2016 Annual Generation Performance

For the twelve months ended December 31, 2016, the Renewable Generation Group generated 3,502.4 GW-hrs of electricity as compared to 3,112.7 GW-hrs during the same period of 2015.

For the twelve months ended December 31, 2016, the hydro facilities generated 604.5 GW-hrs of electricity as compared to 599.6 GW-hrs produced in the same period in 2015, an increase of 0.8%. Electricity generated represented 97.4% of long-term projected average resources as compared to 96.3% during the same period in 2015. During the twelve months ended December 31, 2016, the Western region achieved production above its LTAR, while the Maritime, Quebec and Ontario regions were below their respective LTAR. The Quebec region achieved 106% of its LTAR excluding the Donnacona Hydro Facility which was offline during the period.

For the twelve months ended December 31, 2016, the wind facilities produced 2,586.7 GW-hrs of electricity as compared to 2,221.7 GW-hrs produced in the same period in 2015, an increase of 16.4%. During the twelve months ended December 31, 2016, the wind facilities generated electricity equal to 93.7% of LTAR as compared to 93.7% during the same period in 2015. The increase in production was primarily due to higher production at the Senate, St. Leon and Sandy Ridge Wind Facilities as well as the incremental electricity generated at the Morse and Odell Wind Facilities which achieved commercial operation on April 22, 2015 and July 29, 2016, respectively.

For the twelve months ended December 31, 2016, the solar facilities generated 61.5 GW-hrs of electricity as compared to 47.9 GW-hrs of electricity produced in the same period in 2015, an increase of 28.4%. The increase in production is attributable to a full year of production at the new Bakersfield I Solar Facility which achieved COD on April 14, 2015. The Cornwall Solar Facility's production was 6.1% above its LTAR as compared to 3.4% above its LTAR in the same period last year. The Bakersfield I Solar Facility's production was 13.1% below its LTAR.



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Algonquin Power & Utilities Corp. - Management Commentary

For the twelve months ended December 31, 2016, the thermal facilities generated 249.7 GW-hrs of electricity as compared to 243.5 GW-hrs of electricity during the same period in 2015. During the same period, the Windsor Locks Thermal Facility generated 552.5 billion lbs of steam as compared to 613.0 billion lbs of steam during the same period in 2015.



2016 Renewable Generation Group Operating Results
	Three Months Ended December 31						Twelve Months Ended December 31
(all dollar amounts in $ millions)	2016			2015			2016			2015
Revenue¹
Hydro	$	14.6		$	14.6		$	66.5		$	55.7
Wind	42.6			38.7			128.2			118.1
Solar	1.6			1.6			12.9			10.3
Thermal	8.2			8.1			35.5			38.5
Total Revenue	$	67.0		$	63.0		$	243.1		$	222.6
Less:
Cost of Sales - Energy²	(1.8		)	(1.7		)	(5.8		)	(10.3		)
Cost of Sales - Thermal	(4.4		)	(3.6		)	(15.5		)	(17.7		)
Realized gain/(loss) on hedges³	—			—			(1.0		)	0.6
Net Energy Sales⁵	$	60.8		$	57.7		$	220.8		$	195.2
Renewable Energy Credits ("REC")⁴	6.3			6.1			20.2			18.5
Other Revenue	0.5			0.7			2.4			2.5
Total Net Revenue	$	67.6		$	64.5		$	243.4		$	216.2
Expenses & Other Income
Operating expenses	(20.2		)	(15.0		)	(72.3		)	(63.6		)
Interest, dividend, equity and other income	(0.1		)	(0.7		)	1.4			(0.4		)
Operating Profit from non-Consolidated entities⁵	1.0			0.6			3.8			2.7
HLBV income⁶	13.6			12.6			41.0			33.9
Divisional Operating Profit^7,8	$	61.9		$	62.0		$	217.3		$	188.8



1	While most of the Renewable Generation Group's PPAs include annual rate increases, a change to the weighted average production levels resulting from higher average production from facilities that earn lower energy rates can result in a lower weighted average energy rate earned by the division as compared to the same period in the prior year.
2	Cost of Sales - Energy consists of energy purchases in the Maritime Region to manage the energy sales from the Tinker Hydro Facility which is sold to retail and industrial customers under multi-year contracts.
3	See financial statements note 25(b)(iv).
4	Qualifying renewable energy projects receive Renewable Energy Credits ("REC") for the generation and delivery of renewable energy to the power grid. The energy credit certificates represent proof that 1 MW of electricity was generated from an eligible energy source.
5	When the Renewable Generation Group 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 calculation of divisional operating profit. Certain figures recorded in accordance with GAAP have been adjusted to conform to this presentation.
6	HLBV income represents the value of net tax attributes earned by the Renewable Generation Group in the period from electricity generated by certain of its U.S. wind power and U.S. solar generation facilities.
7	Certain prior year items have been reclassified to conform to current year presentation.
8	See Non-GAAP Financial Measures.



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Algonquin Power & Utilities Corp. - Management Commentary

2016 Fourth Quarter Operating Results

For the three months ended December 31, 2016, the Renewable Generation Group facilities generated $61.9 million of operating profit as compared to $62.0 million during the same period in 2015, which represents a decrease of $0.1 million, excluding corporate administration expenses.

Highlights of the changes are summarized in the following table:



(all dollar amounts in $ millions)	Three Months Ended December 31
Prior Period Operating Profit	$	62.0
Existing Facilities
Hydro: Increase due to higher realized pricing in Ontario and Quebec mainly offset by decreased production and retail demand.	0.1
Wind Canada: Increase in production at the St. Leon and Morse Wind Facilities due to an improved wind resource, partially offset by a decrease in rates due to the expiry of the WPPI at St. Leon Wind Facility.	1.2
Wind U.S.: Decrease primarily due to lower production at Minonk and Shady Oaks Wind Facilities and annual escalation in fees payable under operating and maintenance agreements.	(4.8		)
Solar Canada: Decrease in production due to snow coverage and poor irradiance at the Cornwall Solar Facility.	(0.4		)
Solar U.S.: Increase due to higher production and HLBV income at the Bakersfield I Solar Facility.	0.5
Thermal: Decrease due to production and basis pricing declines at the Sanger Thermal Facility.	(0.3		)
Other: Decrease due to higher development costs, partially offset by a non-recurring equity loss recorded in the prior year.	(1.4		)
	(5.1		)
New Facilities
Wind Canada: Incremental operating profit from the purchase of the Red Lily Wind Facility.	0.9
Wind U.S.: Acquisition of the Odell Wind Facility.	6.0
Solar U.S.: The Bakersfield II Solar Project was placed in service in December 2016 resulting in a recognition of HLBV loss and closing costs.	(1.5		)
	5.4
Foreign Exchange	(0.4		)
Current Period Divisional Operating Profit	$	61.9



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Algonquin Power & Utilities Corp. - Management Commentary

2016 Annual Operating Results

For the twelve months ended December 31, 2016, the Renewable Generation Group facilities generated $217.3 million of operating profit as compared to $188.8 million during the same period in 2015, which represents an increase of $28.5 million or 15.1%, excluding corporate administration expenses.

Highlights of the changes are summarized in the following table:



(all dollar amounts in $ millions)	Twelve Months Ended December 31
Prior Period Operating Profit	$	188.8
Existing Facilities
Hydro: Increase primarily due to the receipt of the retroactive Global Adjustment payments ($8.4 million) from the OEFC and improved hydrology in the Quebec and Maritime regions, as well as a reduction in the volume and cost of energy purchased to satisfy retail load in the Maritime region.	13.4
Wind Canada: Decrease primarily due to lower realized rates resulting from the expiry of WPPI for the St. Leon Wind Facility.	(1.0		)
Wind U.S.: Decrease primarily due to lower production at the Minonk and Shady Oaks Wind Facilities and annual escalation in fees under Operating and Maintenance contracts, partially offset by higher HLBV income due to the reduced economic interest of Tax Equity investors.	(2.1		)
Solar Canada: Small increase in production at the Cornwall Solar Facility which was offset by an increase in operating costs.	—
Thermal: Decrease primarily due to reduced customer demand at the Sanger Thermal Facility, partly offset by declining fuel prices.	(0.8		)
Other: Decrease primarily due to higher development costs offset by the interest earned on the OEFC's Global Adjustment payments and a non-recurring equity loss recorded in the prior year.	(0.6		)
	8.9
New Facilities
Wind Canada: The Morse Wind Facility achieved COD on April 22, 2015.	3.8
Wind Canada: Incremental operating profit from the acquisition of the Red Lily Wind Facility.	2.1
Wind U.S.: Acquisition of the Odell Wind Facility.	7.5
Solar U.S.: Full year results from the Bakersfield I Solar Facility which achieved COD in mid 2015.	2.5
	15.9
Foreign Exchange	3.7
Current Period Divisional Operating Profit	$	217.3



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Algonquin Power & Utilities Corp. - Management Commentary

Development Division

The Development Division 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 Renewable Generation Group’s existing portfolio. The Development Division is focused on projects within North America and is committed to working proactively with all stakeholders including local communities. The Renewable Generation Group’s approach to project development and acquisition is 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 Renewable Generation Group's Development Division will begin construction or execute an acquisition agreement.

The Renewable Generation Group’s Development Division has successfully completed, is constructing, and is developing a number of power generation projects. The 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 credit-worthy counterparties, and meet or exceed the Company's investment return objectives. The projects are as follows:



Project Name	Location	Size (MW)	Estimated Capital Cost (millions)³		Commercial Operation	PPA Term	Production GW-hrs
Projects in Construction
Amherst Island Wind Project	Ontario	75	$	295	2018	20	235
Great Bay Solar Project¹	Maryland	75	195		2017	10	146
Total Projects in Construction		150	$	490			381

Projects in Development
Chaplin/Blue Hill Wind Project	Saskatchewan	177	$	345	2019/20	25	813
Val-Eo Wind Project²	Quebec	24	65		2018	20	66
Total Projects in Development		201	$	410			879
Total in Construction and Development		351	$	900			1,260



1	The total cost of the project is expected to be approximately $145 million in U.S. dollars.
2	All figures refer solely to Phase I of the Val-Eo Wind Project.
3	Estimated capital costs for U.S. based projects have been converted at the exchange rate in effect at the end of the current reporting period.

Projects Recently Completed

Deerfield Wind Project

The Deerfield Wind Project is a 150.0 MW wind powered electric generating development project located in central Michigan and is constructed on approximately 20,000 acres of land leased from a supportive wind power land owner group.

Construction of the project commenced in the fourth quarter of 2015. The project declared commercial operations on February 21, 2017.

The project is the Renewable Generation Group's tenth wind generating facility and consists of 44 Vestas V110-2.0 wind turbines and 28 Vestas V110-2.2 turbines and is estimated to generate 555.2 GW-hrs of energy per year, with all energy, capacity, and renewable energy credits from the project sold to a local electric distribution utility which serves 260,000 customers in Michigan, pursuant to a 20 year PPA.



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Algonquin Power & Utilities Corp. - Management Commentary

The Renewable Generation Group's interest in the project is via a 50% joint venture with the original developer along with an option to acquire the other 50% interest, subject to certain adjustments any time prior to the date that is 90 days following commencement of operations.

Bakersfield II Solar Project

The Bakersfield II Solar Project is a 10 MWac solar powered electric generating project adjacent to the Renewable Generation Group's 20 MW Bakersfield I Solar Project in Kern County, California.

Construction of the project commenced in the second quarter of 2015. The facility declared commercial operations on January 11, 2017.

The facility is the Renewable Generation Group's third solar generating facility and is comprised of approximately 38,640 solar panels located on 64 acres of land. The project is expected to generate 24.2 GW-hrs of energy per year which is being sold under a 20 year PPA with a large investment grade electric utility.

The project qualifies for U.S. federal investment tax credits, and consistent with financing structures utilized for U.S. based renewable energy projects approximately U.S. $12.2 million of financing for the project was sourced from tax equity investors. The financing closed on February 28, 2017 following achievement of commercial operations.

Projects in Construction

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 kilometers southwest of Kingston, Ontario.

The project is currently contemplated to use Class III wind turbine generator technology consisting of 26 Siemens 3.0 MW turbines and is expected to produce approximately 235.0 GW-hrs of electrical energy annually with all energy being sold under a 20 year PPA awarded as part of the Independent Electricity System Operator ("IESO"), formerly the Ontario Power Authority, Feed in Tariff ("FIT") program.

The total cost to complete the project is estimated at approximately $295 million.

The Renewable Energy Approval ("REA") was issued on August 24, 2015 following 29 months of review by the Ontario Ministry of Environment. An appeal of the REA was made to the Environmental Review Tribunal (“ERT”) in 2015. The ERT decision to uphold the REA was issued on August 3, 2016. The project has since conducted final development and procurement efforts and is now under construction. A Divisional Court challenge of the favorable ERT decision was dismissed in the first quarter of 2017.

Since the REA decision, the Company procured the project turbines, submarine cable, and the main power transformer. Negotiations are in progress to engage the balance of plant constructor. Subject to receipt of final permits and negotiation of remaining agreements, final development and construction is expected to be complete in the second quarter of 2018.

Great Bay Solar

The Great Bay Solar Project is a 75.0 MW solar powered electric generating development project located in Somerset County in southern Maryland.

The facility is comprised of 300,000 solar panels and is being constructed on 400 acres of land. The project is expected to generate 146.0 GW-hrs of energy per year, with all energy sold to the U.S. Government Services pursuant to a 10 year PPA, with a 10 year extension option. All Solar Renewable Energy Credits from the project will be retained by the project company and sold into the Maryland market.

Permitting with the county is underway and is expected to be completed in the first quarter of 2017. The project has received its Certificate of Public Convenience and Necessity from the State of Maryland Public Service Commission. The balance of plant and high voltage engineering, procurement, and construction contracts have been executed. The project has a commercial operations date targeted for the end of 2017.

The total costs to complete the project are estimated at approximately U.S. $145.0 million. The Renewable Generation Group expects the project will qualify for U.S. federal investment tax credits and accordingly, approximately 40% of the permanent project financing is expected to be funded by tax equity investors in return for the majority of the tax attributes.

Projects in Development

Chaplin-Blue Hill Wind Project



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The Chaplin-Blue Hill Wind Project is a 177.0 MW wind powered electric generating development project located in Saskatchewan. All of the energy from the project will be sold to SaskPower pursuant to a 25 year PPA awarded in 2012. The project was originally located in the rural municipality of Chaplin, Saskatchewan, 150 km west of Regina, Saskatchewan.

During the year the Saskatchewan Ministry of the Environment determined the original location proposed for the project did not meet its new siting guidelines for wind farms in the Province. As a result, SaskPower and the Company have worked to reconfigure the project in a manner that meets new siting guidelines in the rural municipalities of Morse and Lawtonia.

The Chaplin-Blue Hill project will be developed as a single phase installation beginning in early 2019. All energy from the facility will be sold to SaskPower pursuant to a 25 year PPA that was signed in December 2016. The project requires final environmental approval and all other necessary permitting.

The total costs to complete the project are estimated at approximately $345.0 million but are subject to change depending on turbine selection.

Val-Éo Wind Project

The Val-Éo Wind Project is a 125 MW wind powered electric generating development project located in the local municipality of Saint-Gideon de Grandmont, which is within the regional municipality of Lac-Saint-Jean-Est, Quebec. The project proponents include the Val-Éo Wind Cooperative which was formed by community based landowners and the Renewable Generation Group.

The Renewable Generation Group’s equity interest in the project is subject to final negotiations with the Val-Éo community cooperative but, in any event, will not be less than 25%. 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 $18.0 million.

The project will be developed in two phases: Phase I of the project is expected to be completed in 2018 and will likely be comprised of ten 2.35 MW wind turbines for a total capacity of 24 MW and is expected to generate 66.0 GW-hrs of energy per year, 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. The new schedule calls for Phase I construction to begin in the spring of 2017, with commissioning to occur in 2018.



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LIBERTY UTILITIES GROUP

The Liberty Utilities Group operates rate-regulated utilities that provide distribution services to approximately 565,000 connections in the natural gas, electric, water and wastewater sectors. On January 1, 2017, Liberty Utilities completed the acquisition of Empire. Empire is a vertically-integrated utility providing electric, natural gas and water service serving approximately 218,000 customers in Missouri, Kansas, Oklahoma, and Arkansas. Including Empire, Liberty now serves approximately 783,000 customers. The Liberty Utilities Group's strategy is to grow its business organically and through business development activities while using prudent acquisition criteria. The Liberty Utilities Group believes that its business results are maximized by building constructive regulatory and customer relationships, and enhancing community connections.



Utility System Type	As at December 31
Utility System Type	2016			2015
(all dollar amounts in U.S. $ millions)	Assets		Total Connections¹	Assets		Total Connections¹
Electricity	$	378.4	94,000	$	343.2	93,000
Natural Gas	845.9		293,000	783.0		292,000
Water and Wastewater	516.4		178,000	254.7		104,000
Total	$	1,740.7	565,000	$	1,380.9	489,000

Accumulated Deferred Income Taxes Liability	$	194.7		$	110.3



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

The Liberty Utilities Group aggregates the performance of its utility operations by utility system type – electricity, natural gas, and water and wastewater systems.

The electric distribution systems are comprised of regulated electrical distribution utility systems and serve approximately 94,000 connections in the states of California and New Hampshire.

The natural gas distribution systems are comprised of regulated natural gas distribution utility systems and serve approximately 293,000 connections located in the states of New Hampshire, Illinois, Iowa, Missouri, Georgia, and Massachusetts.

The water and wastewater distribution systems are comprised of regulated water distribution and wastewater collection utility systems and serve approximately 178,000 connections located in the states of Arkansas, Arizona, California, Illinois, Missouri, Montana, and Texas. California and Montana were added during the first quarter of 2016 in connection with the closing of the acquisition of the Park Water System.

2016 Fourth Quarter Usage Results



Electric Distribution Systems	Three Months Ended December 31
	2016	2015
Average Active Electric Connections For The Period
Residential	80,600	79,900
Commercial and industrial	12,500	12,300
Total Average Active Electric Connections For The Period	93,100	92,200

Customer Usage (GW-hrs)
Residential	142.5	135.8
Commercial and industrial	225.0	220.3
Total Customer Usage (GW-hrs)	367.5	356.1

For the three months ended December 31, 2016 the electric distribution systems' usage totaled 367.5 GW-hrs as compared to 356.1 GW-hrs for the same period in 2015, an increase of 11.4 GW-hrs or 3.2%.



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Natural Gas Distribution Systems	Three Months Ended December 31
	2016	2015
Average Active Natural Gas Connections For The Period
Residential	248,100	247,500
Commercial and industrial	26,600	26,600
Total Average Active Natural Gas Connections For The Period	274,700	274,100

Customer Usage (MMBTU)
Residential	3,737,000	3,002,000
Commercial and industrial	3,446,000	2,362,000
Total Customer Usage (MMBTU)	7,183,000	5,364,000

For the three months ended December 31, 2016, usage at the natural gas distribution systems totaled 7,183,000 MMBTU as compared to 5,364,000 MMBTU during the same period in 2015, an increase of 1,819,000 MMBTU, or 33.9%. The increase is primarily due to higher heating degree days in the three months ended December 31, 2016 as compared to the same period in the prior year.



Water and Wastewater Distribution Systems	Three Months Ended December 31
	2016	2015
Average Active Connections For The Period
Wastewater connections	41,100	40,200
Water distribution connections	129,400	58,700
Total Average Active Connections For The Period	170,500	98,900

Gallons Provided
Wastewater treated (millions of gallons)	542	532
Water sold (millions of gallons)	4,113	1,971
Total Gallons Provided	4,655	2,503

During the three months ended December 31, 2016, the water and wastewater distribution systems provided approximately 4,113 million gallons of water to its customers and treated approximately 542 million gallons of wastewater as compared to 1,971 million gallons of water provided and 532 million gallons of wastewater treated during the same period in 2015. The increase in the gallons of water provided to customers can be primarily attributed to the addition of the Park Water System on January 8, 2016. The Park Water system provided approximately 2,074 million gallons of water to customers during the three months ended December 31, 2016.



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2016 Fourth Quarter Operating Results



	Three Months Ended December 31
	2016 U.S. $ (millions)			2015 U.S. $ (millions)			2016 Can $ (millions)			2015 Can $ (millions)
Revenue
Utility electricity sales and distribution	$	46.9		$	40.8		$	62.5		$	54.6
Less: cost of sales – electricity	(20.6		)	(23.1		)	(27.5		)	(30.9		)
Net Utility Sales - electricity	26.3			17.7			35.0			23.7
Utility natural gas sales and distribution	85.1			79.8			114.0			107.2
Less: cost of sales – natural gas	(39.8		)	(36.4		)	(53.2		)	(48.9		)
Net Utility Sales - natural gas	45.3			43.4			60.8			58.3
Utility water distribution & wastewater treatment sales and distribution	31.7			15.3			42.3			20.4
Less: cost of sales – water	(2.2		)	—			(3.0		)	—
Net Utility Sales - water distribution & wastewater treatment	29.5			15.3			39.3			20.4
Gas transportation	8.4			5.7			10.7			7.6
Other revenue	5.0			0.4			6.8			0.5
Net Utility Sales	114.5			82.5			152.6			110.5
Operating expenses	(50.0		)	(39.2		)	(66.8		)	(52.4		)
Other income	0.9			0.8			1.3			1.1
Divisional Operating Profit¹	$	65.4		$	44.1		$	87.1		$	59.2



1	Certain prior year items have been reclassified to conform with current year presentation.

For the three months ended December 31, 2016, the Liberty Utilities Group reported an operating profit (excluding corporate administration expenses) of U.S. $65.4 million as compared to U.S. $44.1 million for the comparable period in the prior year. Measured in Canadian dollars, the group's operating profit was $87.1 million as compared to $59.2 million during the same period in 2015, which represents an increase of $27.9 million or 47%, excluding corporate administration expenses.

Highlights of the changes are summarized in the following table:



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(all dollar amounts in $ millions)	Three Months Ended December 31
Prior Period Operating Profit	$	59.2
Existing Facilities
Electricity: Decrease primarily related to higher operating expenses at the CalPeco and Granite State Electric systems.	(2.7		)
Gas: Increase due to higher revenues at the EnergyNorth, Midstates, and Peach State Gas systems, largely due to higher heating degree days.	4.1
Water: Increase primarily related to higher consumption at the LPSCo and Bella Vista Water systems.	1.5
Other: Increase primarily due to higher revenues for contracted services.	3.3
	6.2
New Facilities
Water: The acquisition of the Park Water System closed on January 8, 2016.	7.7
	7.7
Rate Cases
Electricity: Implementation of new rates at the CalPeco Electric system retroactive back to January 1, 2016.	11.9
Gas: Implementation of new rates at the Peach State and New England Gas Systems.	1.8
Water: Implementation of new rates at the Black Mountain Waste Water System along with the Bella Vista and Rio Rico Water Systems.	0.6
	14.3
Foreign Exchange	(0.3		)
Current Period Divisional Operating Profit	$	87.1

2016 Annual Usage Results



Electric Distribution Systems	Twelve Months Ended December 31
	2016	2015
Average Active Electric Connections For The Period
Residential	80,400	79,900
Commercial and industrial	12,500	12,400
Total Average Active Electric Connections For The Period	92,900	92,300

Customer Usage (GW-hrs)
Residential	567.0	555.0
Commercial and industrial	895.2	898.7
Total Customer Usage (GW-hrs)	1,462.2	1,453.7

For the twelve months ended December 31, 2016 the electric distribution systems' usage totaled 1,462.2 GW-hrs as compared to 1,453.7 GW-hrs for the same period in 2015, an increase of 8.5 GW-hrs. Customer usage at the Granite State Electric system decreased by approximately 21.1 GW-hrs due to warmer weather experienced in the region as compared to the prior year. This decrease was offset by increased customer usage at the CalPeco Electric System which was 29.6 GW-hrs higher as compared to the prior year.



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Natural Gas Distribution Systems	Twelve Months Ended December 31
	2016	2015
Average Active Natural Gas Connections For The Period
Residential	249,000	248,300
Commercial and industrial	26,600	26,700
Total Average Active Natural Gas Connections For The Period	275,600	275,000

Customer Usage (MMBTU)
Residential	15,346,000	17,383,000
Commercial and industrial	12,768,000	12,460,000
Total Customer Usage (MMBTU)	28,114,000	29,843,000

For the twelve months ended December 31, 2016, usage at the natural gas distribution systems totaled 28,114,000 MMBTU as compared to 29,843,000 MMBTU during the same period in 2015, a decrease of 1,729,000 MMBTU or 5.8%. The decrease in natural gas usage as compared to the same period in 2015 can be primarily attributed to a decrease in heating degrees days experienced at the EnergyNorth, Midstates and New England Gas Systems service territories.



Water and Wastewater Distribution Systems	Twelve Months Ended December 31
	2016	2015
Average Active Connections For The Period
Wastewater connections	41,100	40,100
Water distribution connections	131,400	58,800
Total Average Active Connections For The Period	172,500	98,900

Gallons Provided
Wastewater treated (millions of gallons)	2,231	2,168
Water sold (millions of gallons)	17,936	8,457
Total Gallons Provided	20,167	10,625

During the twelve months ended December 31, 2016, the water and wastewater distribution systems provided approximately 17,936 million gallons of water to its customers and treated approximately 2,231 million gallons of wastewater as compared to 8,457 million gallons of water and 2,168 million gallons of wastewater during the same period in 2015. The increase in water provided can be primarily attributed to the acquisition of the Park Water System on January 8, 2016 which provided 7,471 million gallons of water during the year.



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2016 Annual Operating Results



	Twelve Months Ended December 31
	2016 U.S. $ (millions)			2015 U.S. $ (millions)			2016 Can $ (millions)			2015 Can $ (millions)
Revenue
Utility electricity sales and distribution	$	171.7		$	175.6		$	228.1		$	224.1
Less: cost of sales – electricity	(90.0		)	(103.3		)	(119.8		)	(131.6		)
Net Utility Sales - electricity	81.7			72.3			108.3			92.5
Utility natural gas sales and distribution	276.8			339.0			371.4			430.2
Less: cost of sales – natural gas	(105.0		)	(172.0		)	(142.1		)	(217.3		)
Net Utility Sales - natural gas	171.8			167.0			229.3			212.9
Utility water distribution & wastewater treatment sales and distribution	137.4			61.3			181.7			78.4
Less: cost of sales – water	(9.2		)	—			(12.2		)	—
Net Utility Sales - water distribution & wastewater treatment	128.2			61.3			169.5			78.4
Gas transportation	25.7			26.4			34.3			33.5
Other revenue	11.0			13.0			14.6			16.9
Net Utility Sales	418.4			340.0			556.0			434.2
Operating expenses	(194.8		)	(167.3		)	(258.7		)	(214.1		)
Other income	3.9			3.1			5.1			4.0
Divisional Operating Profit¹	$	227.5		$	175.8		$	302.4		$	224.1



1	Certain prior year items have been reclassified to conform with current year presentation.

For the twelve months ended December 31, 2016, the Liberty Utilities Group reported an operating profit (excluding corporate administration expenses) of U.S. $227.5 million as compared to U.S. $175.8 million for the comparable period in the prior year. Measured in Canadian dollars, the group's operating profit was $302.4 million as compared to $224.1 million during the same period in 2015, which represents an increase of $78.3 million or 35%, excluding corporate administration expenses.

Highlights of the changes are summarized in the following table:



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(all dollar amounts in $ millions)	Twelve Months Ended December 31
Prior Period Operating Profit	$	224.1
Existing Facilities
Electricity: The CalPeco and Granite State Electric Systems generated operating profit consistent with the same period in the prior year.	(1.9		)
Gas: Decrease primarily due to a one-time U.S. $3.0 million recoupment of revenue that occurred in the second quarter of 2015 at the EnergyNorth Gas System as permitted pursuant to its 2014 rate case, as well as lower demand at the gas systems due to warmer winter weather resulting in lower heating degree days. This was offset by lower operating costs due to prudent cost management.	(1.2		)
Water: Increase primarily related to higher demand at the LPSCo and Bella Vista Water Systems, and lower operating expenses at the Pine Bluff Water System.	4.7
Other: Decrease primarily due to lower revenues for contracted services and the sale of the water heater rental business in the New England Gas System.	(3.0		)
	(1.4		)
New Facilities
Water: The acquisition of the Park Water System closed on January 8, 2016.	45.5
	45.5
Rate Cases
Electricity: Implementation of new rates at the CalPeco Electric System retroactive back to January 1, 2016 and interim rates at the Granite State Electric System.	12.7
Gas: Implementation of new rates at the Peach State and New England Gas Systems.	10.7
Water: Implementation of new rates at the Black Mountain Waste Water System along with the Bella Vista and Rio Rico Water Systems.	0.8
	24.2
Foreign Exchange	10.0
Current Period Divisional Operating Profit	$	302.4



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Regulatory Proceedings

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



Utility	State	Regulatory Proceeding Type	Rate Request U.S. $ (millions)	Current Status
Completed Rate Cases
Peach State Gas System	Georgia	GRAM	$3.4	Final Order issued in February 2016 approving a U.S. $2.7 million rate increase effective March 1, 2016.
New England Gas System	Massachusetts	General Rate Case	$11.8	Final Order issued in February 2016 approving a U.S. $8.3 million rate increase, with U.S. $7.8 million effective March 1, 2016 and U.S. $0.5 million effective March 1, 2017.
Black Mountain Sewer System	Arizona	General Rate Case	$0.4	Final Order issued in April 2016 approving U.S. $0.2 million rate increase effective May 1, 2016.
Rio Rico Water/Sewer System	Arizona	General Rate Case	$0.9	Application filed in October 2015 seeking a U.S. $0.9 million revenue increase. A final permanent rate decision issued in October 2016 allowed for a U.S. $0.98 million revenue increase effective November 2016.
Bella Vista Water System	Arizona	General Rate Case	$1.6	Application filed in October 2015 seeking a U.S. $1.6 million revenue increase. A final permanent rate decision issued in October 2016 allowed for a U.S. $0.96 million revenue increase effective November 2016.
CalPeco Electric System	California	General Rate Case	$13.6	Application filed in May 2015 seeking a U.S. $13.6 million revenue increase (U.S. $11.4 million related directly to distribution margin) effective January 2016. A settlement agreement was filed in April 2016 and approved by the CPUC in December, 2016. The approved settlement authorized a U.S. $8.3 million margin revenue increase retroactive to Q1 2016.
Peach State Gas System	Georgia	GRAM	$0.6	Application filed in October 2016 seeking a U.S. $0.6 million revenue increase. A final permanent rate decision was issued in January 2017 approving a U.S. $0.7 million increase, with new rates effective February 2017.
Pending Rate Cases
Entrada Del Oro	Arizona	General Rate Case	$0.3	Application filed in March 2016 seeking a U.S. $0.3 million revenue increase. A final permanent rate decision is expected in Q2 2017.
Granite State Electric System	New Hampshire	General Rate Case	$7.7	Application filed in April 2016 seeking a U.S. $7.7 million revenue increase. A temporary rate increase of U.S. $2.4 million became effective July 2016. A final permanent rate decision is expected in Q2 2017.
Illinois Gas System	Illinois	General Rate Case	$3.0	A settlement was filed with the Illinois Commerce Commission ("ICC") which results in the establishment of a decoupling mechanism, bad debt tracker, and enhanced growth mechanism. The settlement will result in annualized revenue increases of $2.3 million and is expected to be implemented in July 2017.
Iowa Gas System	Iowa	General Rate Case	$1.1	A settlement was filed with the Iowa Utilities Board ("IUB") in February 2017 which will result in an annualized revenue increase of U.S. $1.0 million, expected to become effective Q2 2017. A final permanent rate decision is expected in Q2 2017.
Woodmark/Tall Timbers Water & Wastewater Systems	Texas	General Rate Case	$2.0	Application filed in September 2016 seeking a U.S. $2.0 million revenue increase. A final permanent rate decision is expected in Q4 2017.



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Completed Rate Cases

On October 1, 2015, the Peach State Gas System filed an application for an increase in revenue of U.S. $3.4 million in its annual Georgia Rate Adjustment Mechanism ("GRAM") filing with the Georgia Public Service Commission. The GRAM uses a 12 month base period ending June 2015 (historic test year), with adjustments for the 12 months ending September 2016 (forward looking test year). Commission approval was received in February 2016, allowing for a U.S. $2.7 million rate increase effective March 1, 2016. The difference from the original proposed amount was due to tax depreciation rates and the use of revised inflationary factors applied to operating expenses.

On July 16, 2015, the New England Gas System filed an application with the Massachusetts Department of Public Utilities seeking an increase in revenue of U.S. $11.8 million, or 14.6%, based on a test year ending December 31, 2014, adjusted for known and measurable changes. This application represents the first rate case under the Liberty's ownership and the first since 2009. The New England Gas System requested the increase in its general rates due to increasing capital costs associated with maintaining the infrastructure and increases in operating and maintenance expenses. The increase reflects a requested return on equity of 10.4% and a debt/equity structure of 45%/55%. An all-party settlement was achieved and filed in December 2015. The settlement includes a two-step revenue increase totaling U.S. $8.3 million, premised upon a 9.6% return on equity on 50% of capital. A U.S. $7.8 million rate increase occurred on March 1, 2016 and a further U.S. $0.5 million rate increase occurred on March 1, 2017, contingent upon certain employee additions. A decision approving the settlement was received in February 2016.

On June 22, 2015, the Black Mountain Wastewater System filed a rate case and financing application. The application seeks an increase in revenue requirement of U.S. $0.4 million, or 18.75%, based on a test year ending December 31, 2014. This rate case is primarily designed to resolve issues related to rate design and the closure of the treatment plant. No amounts have been removed from rate base in this application. The increase reflects a requested return on equity of 10.8% and a debt/equity structure of 30%/70%. An all-party settlement has been achieved and was filed on January 22, 2016. The settlement includes a revenue increase of U.S. $0.2 million, premised upon a 9.5% return on equity on 70% of capital. A Recommended Opinion and Order was issued on March 25, 2016 supporting the settlement. A final commission decision was issued on April 22, 2016 approving the settlement and implementation of new rates as of May 1, 2016, much earlier than originally expected.

On October 28, 2015, the Rio Rico Water and Wastewater System filed a rate case and financing application. The application seeks a combined increase in revenue requirement of U.S. $0.9 million, based on a test year ending December 31, 2014, a combined rate base of U.S. $14.2 million, a 10.8% return on equity ("ROE") and 70% equity. The proposed revenue increases are U.S. $0.7 million, or 22.6%, for the water division and U.S. $0.2 million, or 15.3%, for the wastewater division. This rate case sought to recover increased operating costs and capital improvements. The rate case also sought approval for the fair value Arizona rate evaluation model (“FARE”), a purchased power adjuster mechanism (“PPAM”) and a property tax adjuster mechanism (“PTAM”). The FARE allows for a periodic update of all components in the revenue requirement (subject to an earnings band). A Comprehensive Settlement Agreement was filed in July 2016, supporting a 9.7% ROE, 70% equity, and a U.S. $0.98 million revenue increase. A Recommended Opinion and Order ("ROO") was issued in October 2016 accepting the settlement. A final decision was issued on November 21, 2016 approving the settlement, with implementation of new rates in November 2016. Its previous rate case was based on a test year ending February 2012.

On October 28, 2015, the Bella Vista Water System filed a rate case and financing application. The application sought an increase in revenue requirement of U.S. $1.6 million, or 33.6%, based on a test year ending December 31, 2014, a rate base of U.S. $13.2 million, 11.6% ROE, and 70% equity. This rate case seeks to recover increased operating costs and capital improvements. It also includes approval for the FARE, a PPAM and a PTAM. A Comprehensive Settlement Agreement was filed in July 2016, supporting a 9.7% ROE, 70% equity, and a U.S. $0.96 million revenue increase. A ROO was issued in October 2016 accepting the settlement. A final decision was issued on November 21, 2016 approving the settlement, with implementation of new rates in November 2016. Its previous rate case was based on a test year ending March 2009.

On May 1, 2015, the CalPeco Electric System filed an application with the CPUC seeking an increase in revenue of U.S. $13.6 million (of which U.S. $11.4 million related to an increase in distribution margin revenue, and the remainder related to energy costs and other non-distribution charges), or 17.3%, based on a test year ending December 31, 2014, with pro forma changes to certain operating expenses and rate base capital additions. The increase reflects a requested 10.5% ROE, and 55% equity. The previous test year ended December 31, 2011. In May 2016, an all-party settlement was filed with the CPUC allowing for a U.S. $9.8 million net distribution margin revenue increase, or approximately 86% of the requested increase. The increase reflects a 10.0% ROE and 52.5% equity. A final permanent rate decision from the CPUC was received in the fourth quarter of 2016, approving the settlement with a revision to the treatment of tax repairs in rates. This revision lowered the approved revenue increase to U.S. $8.3 million. The new permanent rates will be implemented January 2017, and will reflect retroactive effectiveness to the first quarter of 2016.

On October 1, 2016, the Georgia Gas System filed its annual GRAM. The application seeks a U.S. $0.6 million annual revenue increase to a proposed revenue requirement of U.S. $31.3 million, or a 1.9% increase, based on test year ending



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June 2016. The GRAM proposals include a 10.5% ROE, 55.0% equity, and a U.S. $99.0 million rate base. PSC approval was received Q1 2017, allowing a U.S. $0.7 million increase, with implementation of new rates in February 2017.

Pending Rate Cases and Other Regulatory Applications

On March 3, 2016, the Entrada Del Oro Wastewater System filed a rate case and financing application. The application seeks an increase in revenue requirement of U.S. $0.3 million, or 90.5%, based on a test year ending October 31, 2015, a rate base of U.S. $2.2 million, 12% ROE, and 70% equity. Rates are proposed to be phased in over two years due to the magnitude of the increase. This rate case seeks to recover increased operating costs and capital improvements. An all-party settlement was filed with the ACC in Q1 2017, allowing a revenue increase of U.S. $0.2 million. A final decision and implementation of new rates is expected for the second quarter of 2017. Its previous rates became effective July 2006.

On April 29, 2016, the Granite State Electric System filed a rate application. The application seeks a U.S. $5.3 million annual revenue increase proposed for effect July 1, 2016, or a 15.0% increase to distribution revenue, plus an additional U.S. $2.4 million annual increase (step increase) to recover the revenue requirement associated with capital additions made in 2016. The total permanent and step increase being proposed is U.S. $7.7 million annually, or a 21.8% increase to distribution revenue. In June 2016, approval of a temporary rate increase of U.S. $2.4 million was issued, effective July 1, 2016. The final permanent revenue increase will be retroactive to the temporary rate effective date. The step increase would become effective at the time permanent rates become effective following the close of the proceeding. A Final Order is expected in the second quarter of 2017.

On July 25, 2016, the Illinois Gas System filed a rate application. The application seeks a U.S. $3.0 million annual revenue increase to a proposed revenue requirement of U.S. $15.3 million, or a 24% increase, based on a 2017 projected test year. Proposals include a 10.3% ROE, 54% equity, 4.83% cost of debt, 7.8% WACC, and a U.S. $45.0 million rate base. On February 17, 2017, a settlement was filed which calls for an annual revenue increase of $2.3 million, the establishment of a decoupling mechanism, a bad debt tracking mechanism, and a mechanism to enable further system expansion. A Final Order is expected in May 2017. Its previous rate case was filed in March 2014 and was based on a 2015 projected test year.

On July 25, 2016, the Iowa Gas System filed a rate application. The application seeks a U.S. $1.1 million annual revenue increase to a proposed revenue requirement of U.S. $3.2 million, or a 46% increase, based on a 2015 historical test year with pro-forma changes to June 2016. Proposals include a 10.25% ROE, 54% equity, 4.8% cost of debt, 7.76% WACC, and a U.S. $6.5 million rate base. Interim rates became effective August 4, 2016, allowing an interim revenue increase of U.S. $0.5 million on an annualized basis, or 50% of total proposed increase. On February 17, 2017, a settlement was filed which calls for an annual revenue increase of U.S. $1.0 million. A Final Order is expected in May 2017. Its previous rate case took place in 2001.

On September 2, 2016, the Woodmark and Tall Timbers Wastewater Systems filed a rate application with the Texas Public Utilities Commission. The application seeks a combined, phased-in U.S. $2.0 million annual revenue increase to a proposed revenue requirement of U.S. $4.7 million, or a 71.0% increase, based on a 2015 historical test year with pro-forma adjustments. Proposals include a 10.2% ROE, 70.0% equity, 4.95% cost of debt, 8.6% WACC, and a combined U.S. $11.9 million rate base. The proposed increase consists of two steps with the initial increase of U.S. $1.0 million based on the historical 2015 test year, and a second step of U.S. $1.0 million to recognize the incremental rate base associated with investments in the Woodmark treatment plant expansion and a Tall Timbers line relocation beyond the historical test year. A Final Order is expected in the fourth quarter of 2017.

Park Water System Acquisition

On January 8, 2016, the Liberty Utilities Group completed the acquisition of Western Water Holdings, a company which through its subsidiaries owns three regulated water utilities engaged in the production, treatment, storage, distribution, and sale of water in southern California and western Montana. The three utilities collectively serve approximately 74,000 customer connections and have more than 1,000 miles of distribution mains. Mountain Water Company is the water utility in western Montana serving customers in and around the municipality of Missoula. Mountain Water Company is owned by Liberty Utilities (Park Water) Corp.

Mountain Water Company is currently the subject of a condemnation lawsuit filed by the city of Missoula. Please see the "Regulatory Risk Section: Condemnation Expropriation Proceedings" for further discussion.

The Empire District Electric Company Acquisition

On February 9, 2016, the Liberty Utilities Group announced an agreement and plan of merger pursuant to which Liberty Utilities will indirectly acquire Empire and its subsidiaries. Empire is a Joplin, Missouri based regulated electric, gas (through its wholly-owned subsidiary The Empire District Gas Company), and water utility, collectively serving approximately 218,000 customers in Missouri, Kansas, Oklahoma, and Arkansas.

The final regulatory approval required for the acquisition from the Kansas Corporation Commission was received in December 2016 and the transaction closed on January 1, 2017.



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Algonquin Power & Utilities Corp. - Management Commentary

APUC: CORPORATE AND OTHER EXPENSES



	Three Months Ended December 31						Twelve Months Ended December 31
(all dollar amounts in $ millions)	2016			2015			2016			2015
Corporate and other expenses:
Administrative expenses	$	13.1		$	12.6		$	46.3		$	39.8
(Gain)/Loss on foreign exchange	1.3			0.3			(0.4		)	(2.6		)
Interest expense on convertible debentures and acquisition facility related to the acquisition of Empire	18.2			—			57.6			—
Interest expense	20.5			17.4			74.0			66.0
Interest, dividend, equity, and other income¹	(3.1		)	(2.0		)	(5.5		)	(4.0		)
Other gains²	(0.8		)	(1.0		)	(11.8		)	(2.2		)
Acquisition-related costs	2.4			0.5			12.0			1.8
Gain on derivative financial instruments	(12.9		)	—			(15.8		)	(2.2		)
Income tax expense	11.5			11.8			37.1			43.7



1	Excludes income directly pertaining to the Renewable Generation and Liberty Utilities Groups (disclosed in the relevant sections).
2	Includes Other Gains and loss/(gain) on long-lived assets per the Statement of Operations.

2016 Fourth Quarter Corporate and Other Expenses

During the three months ended December 31, 2016, administrative expenses totaled $13.1 million as compared to $12.6 million in the same period in 2015. The $0.5 million increase primarily relates to additional costs incurred to administer APUC's operations as a result of the Company's growth.

For the three months ended December 31, 2016, interest expense on convertible debentures and acquisition financing totaled $18.2 million (see Convertible Unsecured Subordinated Debentures and note 14 in the Audited Consolidated Financial Statements). Convertible debentures, which are expected to convert to common shares upon closing of the Empire acquisition, were issued to finance the equity required for the transaction. Please see note 14 of the financial statements for further disclosure.

For the three months ended December 31, 2016, interest expense totaled $20.5 million as compared to $17.4 million in the same period in 2015. The interest expense for the period is a result of a U.S. $235.0 million Corporate Term Facility entered into in January 2016, and the assumed debt on the acquisition of the Park Water System.

For the three months ended December 31, 2016, other gains totaled a gain of $0.8 million as compared to a gain of $1.0 million in the same period in 2015. The decrease is primarily due to the recognition of deferred income on repairs completed for facilities where the insurance proceeds have been received in advance during the same period in 2015.

For the three months ended December 31, 2016, gain on derivative financial instruments totaled $12.9 million as compared to nil in the same period in 2015. The increase was primarily driven by mark-to-market gains on foreign currency derivatives.

For the three months ended December 31, 2016, an income tax expense of $11.5 million was recorded as compared to an income tax expense of $11.8 million during the same period in 2015. The decrease in income tax expense is primarily due to the impact of additional interest expense on the convertible debentures offset by the impact of increased earnings from operations.

2016 Annual Corporate and Other Expenses

During the twelve months ended December 31, 2016, administrative expenses totaled $46.3 million as compared to $39.8 million in the same period in 2015. The increase primarily relates to additional costs incurred to administer APUC's operations as a result of the Company's growth and a stronger U.S. dollar. For the twelve months ended December 31, 2016, interest expense on convertible debentures and bridge financing totaled $57.6 million (see Convertible Unsecured Subordinated Debentures and note 14 in the Audited Consolidated Financial Statements).

For the twelve months ended December 31, 2016, interest expense totaled $74.0 million as compared to $66.0 million in the same period in 2015. The increase in interest expense for the period is a result of new indebtedness including: U.S. $160.0 million private placement issued in the second quarter of 2015, U.S. $235.0 million Corporate Term Facility entered into in January 2016, the assumed debt on the acquisition of the Park Water System, and repayments of the Shady Oaks Wind Facility senior debt in the second quarter of 2015. These items were partially offset by higher capitalized interest.



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Algonquin Power & Utilities Corp. - Management Commentary

For the twelve months ended December 31, 2016, other gains totaled a gain of $11.8 million as compared to a gain of $2.2 million in the same period in 2015. The increase is primarily due to: (i) the recognition of deferred income on repairs completed for facilities where the insurance proceeds have been received in advance; and (ii) the settlement of litigation and bankruptcy proceedings relating to Trafalgar Power Inc. (see note 18 in the financial statements) partially offset by (iii) the write-down of the Company's equity interest in the natural gas development projects which have been cancelled by the developer.

For the twelve months ended December 31, 2016, acquisition related costs totaled $12.0 million as compared to $1.8 million in the same period in 2015. The increase in costs are primarily due to $6.0 million due to the closing of the Park Water System, $1.3 million due to the Apple Valley Water System condemnation proceedings, and $3.1 million due to the Empire acquisition. Acquisition related costs will vary from period to period depending on the level of activity and complexity associated with various acquisitions.

For the twelve months ended December 31, 2016, the gain on derivative financial instruments totaled $15.8 million as compared to a gain of $2.2 million in the same period in 2015. The increase was due to mark-to market gains on foreign currency hedges offset by losses on the ineffective portion of derivative financial instruments accounted for as derivatives.

An income tax expense of $37.1 million was recorded in the twelve months ended December 31, 2016 as compared to an income tax expense of $43.7 million during the same period in 2015. The decrease in income tax expense for the twelve months ended December 31, 2016 is primarily due to decreased taxable earnings as a result of additional interest expense on the convertible debentures and a one-time non-cash charge of $2.7 million to deferred income taxes recorded during the twelve months ended December 31, 2015 as a result of an agreement reached with the Canada Revenue Agency (“CRA”) related to the Unit Exchange Transaction.

NON-GAAP PERFORMANCE MEASURES

Reconciliation of Adjusted EBITDA to Net Earnings

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



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	Three Months Ended December 31						Twelve Months Ended December 31
(all dollar amounts in $ millions)	2016			2015			2016			2015
Net earnings attributable to shareholders	$	46.3		$	38.0		$	130.9		$	117.5
Add (deduct):
Net earnings / (loss) attributable to the non-controlling interest, exclusive of HLBV	(2.4		)	0.6			1.9			2.0
Equity loss from non-consolidated entities	0.1			—			1.7			—
Operating profit from non-consolidated entities	1.5			—			3.9			—
Loss from discontinued operations, net of tax	—			0.1			—			1.0
Income tax expense	11.5			11.8			37.1			43.7
Interest expense on convertible debentures and bridge financing	18.2			—			57.6			—
Interest expense	20.5			17.4			74.0			66.0
Other gains	—			(2.1		)	(8.6		)	(5.1		)
(Gain)/loss on long-lived assets	(0.8		)	1.1			(3.3		)	2.9
Acquisition related costs	2.4			0.5			12.0			1.8
Gain on derivative financial instruments	(12.9		)	—			(15.8		)	(2.2		)
Realized gain / (loss) on energy derivative contracts	—			—			(1.0		)	0.6
(Gain) / loss on foreign exchange	1.3			0.3			(0.4		)	(2.6		)
Depreciation and amortization	52.6			41.9			186.9			149.8
Adjusted EBITDA	$	138.3		$	109.6		$	476.9		$	375.4

HLBV represents the value of net tax attributes earned by the Renewable Generation Group in the period from electricity generated by certain of its U.S. wind power and U.S. solar generation facilities. HLBV earned in the three and twelve months ended December 31, 2016 amounted to $13.6 million and $41.0 million respectively.



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Algonquin Power & Utilities Corp. - Management Commentary

Reconciliation of Adjusted Net Earnings to Net Earnings

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

The following table shows the reconciliation of net earnings to Adjusted Net Earnings exclusive of these items:



	Three Months Ended December 31						Twelve Months Ended December 31
(all dollar amounts in $ millions)	2016			2015			2016			2015
Net earnings attributable to shareholders	$	46.3		$	38.0		$	130.9		$	117.5
Add (deduct):
Loss from discontinued operations	—			0.1			—			1.8
Gain on derivative financial instruments	(12.9		)	—			(15.8		)	(2.2		)
Realized gain / (loss) on derivative financial instruments	—			—			(1.0		)	(0.9		)
Loss (gain) on long-lived assets	(0.8		)	1.1			(3.3		)	2.9
Deferred tax expense due to an agreement with the CRA related to the Unit Exchange Transaction	—			—			—			2.7
(Gain) / Loss on foreign exchange	1.3			0.3			(0.4		)	(2.6		)
Interest expense on convertible debentures and bridge financing fees	18.2			—			57.6			—
Acquisition costs	2.4			0.5			12.0			1.8
Adjustment for taxes	(3.1		)	(0.3		)	(18.4		)	0.5
Adjusted Net Earnings	$	51.4		$	39.7		$	161.6		$	121.5
Adjusted Net Earnings per share¹	$	0.18		$	0.15		$	0.57		$	0.46



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

For the three months ended December 31, 2016, Adjusted Net Earnings totaled $51.4 million as compared to Adjusted Net Earnings of $39.7 million, an increase of $11.7 million as compared to the same period in 2015. The increase in Adjusted Net Earnings for the three months ended December 31, 2016 is primarily due to increased earnings from operations partially offset by higher depreciation and amortization expense as compared to 2015.

For the twelve months ended December 31, 2016, Adjusted Net Earnings totaled $161.6 million as compared to Adjusted Net Earnings of $121.5 million, an increase of $40.1 million as compared to the same period in 2015. The increase in Adjusted Net Earnings for the twelve months ended December 31, 2016 is primarily due increased earnings from operations partially offset by higher depreciation and amortization expense as compared to 2015.



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Algonquin Power & Utilities Corp. - Management Commentary

Reconciliation of Adjusted Funds from Operations to Cash Flows from Operating Activities

The following table is derived from and should be read in conjunction with the audited consolidated statement of operations and audited consolidated statement of cash flows. This supplementary disclosure is intended to more fully explain disclosures related to Adjusted Funds from Operations and provides additional information related to the operating performance of APUC. Investors are cautioned that this measure should not be construed as an alternative to funds from operations in accordance with GAAP.

The following table shows the reconciliation of funds from operations to Adjusted Funds from Operations exclusive of these items:



	Three Months Ended December 31						Twelve Months Ended December 31
(all dollar amounts in $ millions)	2016			2015			2016			2015
Cash flows from operating activities	$	121.3		$	94.3		$	287.3		$	261.9
Add (deduct):
Changes in non-cash operating items	(46.7		)	(17.7		)	(3.7		)	11.1
Cash used in discontinued operations	—			0.1			—			1.8
Production based cash contributions from non-controlling interests	—			—			9.5			10.8
Interest expense on convertible debentures and bridge financing fees	18.2			—			57.6			—
Acquisition costs	2.4			0.5			12.0			1.8
Cash generated from sale of long-lived assets	—			—			(8.6		)	—
Cash generated from non-consolidated entities	0.6			—			1.7			—
Adjusted Funds from Operations	$	95.8		$	77.2		$	355.8		$	287.4

For the three months ended December 31, 2016, Adjusted Funds from Operations totaled $95.8 million as compared to Adjusted Funds from Operations of $77.2 million, an increase of $18.6 million as compared to the same period in 2015.

For the twelve months ended December 31, 2016, Adjusted Funds from Operations totaled $355.8 million as compared to Adjusted Funds from Operations of $287.4 million, an increase of $68.4 million as compared to the same period in 2015.

SUMMARY OF PROPERTY, PLANT, AND EQUIPMENT EXPENDITURES¹



	Three Months Ended December 31				Twelve Months Ended December 31
(all dollar amounts in $ millions)	2016		2015		2016		2015
Renewable Generation Group:
Maintenance	$	21.0	$	11.2	$	58.6	$	27.4
Investment in Capital Projects¹	169.0		43.9		538.1		178.7
	$	190.0	$	55.1	$	596.7	$	206.1

Liberty Utilities Group:
Rate Base Maintenance	$	27.0	$	27.3	$	102.7	$	82.5
Rate Base Growth	96.0		5.4		133.7		30.5
	123.0		32.7		236.4		113.0
Corporate	5.0		8.3		29.7		31.2
Total Capital Expenditures	$	318.0	$	96.1	$	862.8	$	350.3



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



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Algonquin Power & Utilities Corp. - Management Commentary

2016 Fourth Quarter Property Plant and Equipment Expenditures

During the three months ended December 31, 2016, the Renewable Generation Group incurred capital expenditures of $190.0 million as compared to $55.1 million during the same period in 2015. At the end of 2016, the Renewable Generation Group purchased approximately $75 million of turbine components ("Safe Harbor Turbines") 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 IRS 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 Renewable Generation Group is currently evaluating projects to maximize the value of this equipment.

The remaining capital expenditures primarily relate to construction at the Donnacona Hydro Facility and the Bakersfield II Solar Project, as well as development spending at the Great Bay Solar, the Chaplin-Blue Hill and Amherst Island Wind Projects. The prior year investment was related to completion of the Bakersfield II Solar Facilities in addition to continued development of the Great Bay Solar and Amherst Island Wind Projects.

During the three months ended December 31, 2016, the Liberty Utilities Group invested $123.0 million in capital expenditures as compared to $32.7 million during the same period in 2015. The Liberty Utilities Group’s investment was primarily related to reliability enhancements, improvements and replenishment opportunities, and leak prone pipe replacements, leak repairs and pipeline corrosion protection initiatives relating to safety and reliability at the electric and gas systems. Specific projects that the capital expenditures relate to include partial financing of the Luning Solar project located in Mineral County, Nevada.

Corporate spending includes transmission operations spend on the Phase I of the North Lake Take System upgrade. Phase I involves the upgrading the 650 Line (10 miles) which runs from Northstar to Kings Beach, California to 120kV.

2016 Annual Property Plant and Equipment Expenditures

During the twelve months ended December 31, 2016, the Renewable Generation Group incurred capital expenditures of $596.7 million as compared to $206.1 million during the same period in 2015. At the end of 2016, the Renewable Generation Group purchased approximately $75 million of Safe Harbor Turbines. During the year, the Renewable Generation Group incurred $343.9 million as a result of the acquisition of the Odell Wind Project. Of the total cost, $236.1 million was received from Tax Equity Investors. Throughout the year, the Renewable Generation Group continued construction of the Bakersfield II Solar Project as well as advanced development of its Great Bay Solar, Amherst Island Wind and Chaplin-Blue Hill Wind projects.

During the twelve months ended December 31, 2016, the Liberty Utilities Group invested $236.4 million in capital expenditures as compared to $113.0 million during the same period in 2015. The Liberty Utilities Group’s investment was primarily related to reliability enhancements, improvements and replenishment opportunities, and leak prone pipe replacements, leak repairs and pipeline corrosion protection initiatives relating to safety and reliability at the electric and gas systems. Specific projects that the capital expenditures relate to include partial financing of the Luning Solar project located in Mineral County, Nevada.

2017 Capital Investments

In 2017, the company plans to spend between $1.1 billion and $1.3 billion on capital investment opportunities. Actual expenditures during the course of 2017 may vary due to timing on various project investments and the realized U.S. dollar exchange rate.

Expected 2017 capital investment ranges are as follows:



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Algonquin Power & Utilities Corp. - Management Commentary



(all dollar amounts in $ millions)
Renewable Generation Group:
Maintenance	$	40.0	-	$	50.0
Investment in Capital Projects	500.0		-	580.0
Total Renewable Generation Group:	$	540.0	-	$	630.0

Liberty Utilities Group:
Rate Base Maintenance	$	160.0	-	$	170.0
Rate Base Growth	400.0		-	500.0
Total Liberty Utilities Group:	$	560.0	-	$	670.0

Total 2017 Capital Investments	$	1,100.0	-	$	1,300.0

APUC anticipates that it can generate sufficient liquidity through internally generated operating cash flows, funds committed by tax equity investors, revolving credit facilities, as well as the debt and equity capital markets to finance its 2017 capital investments.

LIQUIDITY AND CAPITAL RESERVES

APUC has revolving credit and letter of credit facilities available for Corporate, the Renewable Generation Group, and the Liberty Utilities Group to manage the liquidity and working capital requirements of each division (collectively the “Bank Credit Facilities”).

Bank Credit Facilities

The following table sets out the Bank Credit Facilities available to APUC and its operating groups as at December 31, 2016:



	As at December 31, 2016												As at Dec 31, 2015
(all dollar amounts in $ millions)	Corporate			Generation			Utilities			Total			Total
Committed facilities	$	65.0		$	440.3		$	268.5		$	773.8		$	783.3
Funds drawn on facilities	—			(242.9		)	—			(242.9		)	(27.3		)
Letters of credit issued	(12.1		)	(180.9		)	(41.9		)	(234.9		)	(164.4		)
Liquidity available under the facilities	52.9			16.5			226.6			296.0			591.6
Cash on hand										110.4			124.8
Total Liquidity and Capital Reserves	$	52.9		$	16.5		$	226.6		$	406.4		$	716.4

As at December 31, 2016, the Company's $65.0 million senior unsecured revolving credit facility (the "Corporate Credit Facility") was undrawn and had $12.1 million of outstanding letters of credit. The facility matures on November 19, 2017 and is subject to customary covenants.

As at December 31, 2016, the Renewable Generation Group's facilities consisted of a $350.0 million Generation Credit Facility and $90.3 million Generation Letter of Credit Facility (Cdn $50.0 million and U.S. $30.0 million). As at December 31, 2016, the group had drawn $242.9 million and had $180.9 million in outstanding letters of credit. The facilities mature on July 31, 2019 and October 30, 2016, respectively, and are subject to customary covenants. Subsequent to quarter end, the Company extended the maturity of the Generation Letter of Credit Facility to October 31, 2017.

As at December 31, 2016, the Liberty Utilities Group's $268.5 million (U.S. $200.0 million) senior unsecured revolving credit facility ("Liberty Credit Facility") was undrawn and had $41.9 million (U.S. $31.2 million) of outstanding letters of credit. The facility matures on September 30, 2018 and is subject to customary covenants.

As part of the Park Water System's acquisition on January 8, 2016, the Company assumed U.S. $22.5 million of debt outstanding under a non-revolving term credit facility. The term credit facility bears a variable interest rate based on LIBOR plus a credit spread and matures in 2019 but is repayable on demand without penalty.

On February 9, 2016, in connection with the acquisition of Empire, the Company obtained U.S. $1.6 billion in acquisition financing commitments ("Acquisition Facility") from a syndicate of banks. Upon receiving the initial instalment from the Debentures (described below), the Company reduced the commitments under the Acquisition Facility by U.S. $263.6 million. On December 30, 2016 the Company drew U.S. $1,336.4 million on the Acquisition Facility. The funds drawn were transferred to a paying agent for purposes of distribution to holders of the common shares of Empire (see note 3(a) on the Company's Audited Consolidated Financial Statements) on January 1, 2017. The Acquisition Facility matures on December 29, 2017



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Algonquin Power & Utilities Corp. - Management Commentary

and is subject to an initial funding fee payment on March 30, 2017 calculated on the balance drawn on the that date. The Acquisition Facility is subject to margin step ups and duration fees that commence on March 30, 2017 and are calculated based on the amounts drawn.

Subsequent to year end, on February 7, 2017, upon receipt of the Final Instalment from the Debentures, the Company repaid U.S. $567.6 million under the Acquisition Facility. The remaining funds drawn are expected to be repaid on March 24, 2017 from proceeds received from the Liberty Private Placement discussed below and general corporate funds.

Long Term Debt

On January 4, 2016 a subsidiary of the Company entered into a U.S. $235.0 million term credit facility with two U.S. banks ("Corporate Term Facility"). The proceeds of the term credit facility provide the company with additional liquidity for general corporate purposes and acquisitions. The facility matures on July 5, 2018, and is subject to customary covenants.

Subsequent to year end, on January 17, 2017 the Renewable Generation Group issued $300.0 million of senior unsecured debentures bearing interest at 4.09% 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 Renewable Generation Group entered into a cross currency swap, coterminous with the debentures, to economically convert the Canadian dollar denominated offering into U.S. dollars for an effective yield of 4.86%.

Subsequent to year end, on March 1, 2017, the Liberty Utilities Group entered into a Note Purchase Agreement for the issuance of U.S. $750.0 million of senior unsecured notes ("Liberty Private Placement") with 29 institutional investors in the U.S. and Canada. The notes are of varying maturities from 3 to 30 years with a weighted average life of approximately 15 years and a weighted average coupon of 4.0%. In anticipation of the financing, Liberty Utilities had entered into forward contracts to lock in the underlying U.S. Treasury interest rates (see "Interest Rate Risk section"). Considering the effect of the hedges, the effective weighted average rate paid by Liberty Utilities is 3.6%. The closing of the offering is scheduled to occur on March 24, 2017, with the proceeds to be applied to repay the balance of the Acquisition Facility and other existing indebtedness.

As at December 31, 2016, the weighted average tenure of APUC's total long term debt is approximately 9.1 years with an average interest rate of 4.9%.

On September 16, 2016, Revenu Québec issued a notice of assessment in regards of the Company's Canadian renewable and conservation expense ("CRCE") refundable tax credit claim for the St. Damase Wind Facility in an amount of $14.3 million. The Company received payment on October 6, 2016, the proceeds of which were used to pay down drawings under the Generation Credit Facility.

Convertible Unsecured Subordinated Debentures

On March 1, 2016, in connection with the acquisition of Empire, the Company completed the sale of $1.0 billion aggregate principal amount of 5.0% convertible debentures ("Debentures"). On March 9, 2016, the underwriters exercised their option to purchase $150 million additional debentures, bringing the total amount of the offering to $1.15 billion.

The convertible debentures were sold on an instalment basis at a price of $1,000 principal amount debenture, of which $333 was received on closing of the debenture offering and the remaining $667 (the “Final Instalment”) is receivable on a date (“Final Instalment Date”) to be fixed following satisfaction of conditions precedent to the closing of the acquisition of Empire (note 3(a)). The proceeds received from the initial instalment were approximately $383.0 million.

The convertible debentures mature on March 31, 2026 and bear interest at an annual rate of 5% per $1,000 dollars principal amount of convertible debentures until and including the Final Instalment Date, and bears an interest rate of 0% thereafter.

The Final Instalment Date took place, subsequent to year-end, on February 2, 2017. The proceeds received from the Final instalment were $767.1 million. As the Final Instalment Date occurred prior to the first anniversary of the closing of the debenture offering, holders of the convertible debentures who paid the final instalment by February 2, 2017 received, in addition to the payment of accrued and unpaid interest, a make-whole payment representing the interest that would have accrued from the day following the Final Instalment Date up to and including March 1, 2017.

APUC will issue up to 108,490,556 common shares on conversion of all debentures. As at March 1, 2017, a total of 107,517,895 common shares of the company were issued, representing conversion into common shares of 99.1% of the convertible debentures. After the Final Instalment Date, any debentures not converted may be redeemed by the Company at a price equal to their principal amount plus any unpaid interest which accrued prior to and including the Final Instalment Date. At maturity, the Company 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 Toronto Stock Exchange for the 20 consecutive trading days ending five trading days preceding the maturity date.



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Algonquin Power & Utilities Corp. - Management Commentary

Credit Ratings

APUC has a long term consolidated corporate credit rating of BBB (flat) from Standard & Poor's ("S&P") and a BBB (low) rating from DBRS Limited ("DBRS"). Algonquin Power Co ("APCo") has a BBB (flat) issuer rating from S&P and BBB (low) issuer rating from DBRS. Liberty Utilities Finance GP1 ("Liberty Finance"), a special purpose financing entity of Liberty Utilities Co., has a BBB (high) issuer rating from DBRS.

Subsequent to year end, on February 6, 2017, following the announcement that APUC had received the Final Instalment proceeds from the Debentures, S&P revised the outlook on APUC's consolidated corporate credit rating from negative to stable. S&P had placed APUC's consolidated credit rating on negative watch on February 9, 2016, pending the completion of the Empire acquisition and the execution on the financing plan, including the receipt of the Final Instalment and conversion of the Debentures to common shares of the Company. S&P's reiteration of the outlook reflects their assessment of APUC's stable cash flows from its regulated utilities and contracted unregulated power business, along with its commitment to a balance between debt and equity to fund its acquisition and development activities such that its funds from operations-to-debt ratio remains in the 14%-15% range.

Subsequent to year end, on February 13, 2017, following the announcement that APUC had received the Final Instalment proceeds from the Debentures, DBRS removed the "Under Review with Developing Implications" status from the ratings of APUC and its subsidiaries. DBRS had placed APUC's ratings as "Under Review with Developing Implications" on February 10, 2016 pending completion of the acquisition and execution of the financing plan, including the receipt of the Final Instalment proceeds. DBRS reiterated their view that the acquisition of Empire will have a positive impact on APUC’s and Liberty Finance's business risk assessment. The impact on their financial risk assessment was cited as modestly negative, with the overall impact on the ratings as neutral. DBRS also reiterated that the rating actions for APCo reflect their view that the acquisition of Empire has no impact on the business or financial risk assessments of APCo.

Contractual Obligations

Information concerning contractual obligations as of December 31, 2016 is shown below:



(all dollar amounts in $ millions)	Total		Due less than 1 year		Due 1 to 3 years		Due 4 to 5 years		Due after 5 years
Principal repayments on debt obligations¹	$	3,901.3	$	1,871.9	$	745.3	$	304.9	$	979.2
Convertible debentures	358.6		—		—		—		358.6
Advances in aid of construction	105.2		3.1		—		—		102.1
Interest on long-term debt obligations	806.2		194.8		153.0		110.7		347.7
Purchase obligations	398.9		398.9		—		—		—
Environmental obligations	76.8		4.0		23.9		7.1		41.8
Derivative financial instruments:
Cross currency swap	95.4		4.1		7.7		49.4		34.2
Interest rate swap	13.4		—		13.4		—		—
Purchased power	214.9		63.3		74.0		77.6		—
Gas delivery, service and supply agreements	258.4		62.2		82.9		49.0		64.3
Service agreements	721.1		41.4		84.8		91.2		503.7
Capital projects	86.4		66.7		19.6		0.1		—
Operating leases	157.2		7.3		13.4		12.9		123.6
Other obligations	79.8		32.6		—		—		47.2
Total Obligations	$	7,273.6	$	2,750.3	$	1,218.0	$	702.9	$	2,602.4



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

Equity

The common shares of APUC are publicly traded on the Toronto Stock Exchange (“TSX”) and the New York Stock Exchange ("NYSE") under the trading symbol "AQN". As at December 31, 2016, APUC had 274,087,018 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



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Algonquin Power & Utilities Corp. - Management Commentary

remaining property and assets of APUC upon liquidation, dissolution or winding up of APUC. All shares are of the same class and with equal rights and privileges and are not subject to future calls or assessments.

On February 9, 2016, in connection with the acquisition of Empire, APUC and its direct wholly-owned subsidiary, Liberty Utilities (Canada) Corp., entered into an agreement with a syndicate of underwriters under which the underwriters agreed to buy, on a bought deal basis, $1.0 billion aggregate principal amount of 5.00% convertible unsecured subordinated debentures of APUC. On March 9, 2016, the Underwriters exercised their option to purchase an additional $150.0 million of Debentures, bringing the total amount of Debentures under the Debenture Offering to $1.15 billion.

All Debentures were sold on an instalment basis at a price of $1,000 dollars per Debenture, of which $333 dollars was paid on the closing of the Offering and the remaining $667 dollars was payable on a date set by APUC upon satisfaction of all conditions precedent to the closing of APUC's acquisition of Empire. On the Final Instalment Date each debenture was convertible to 94.3396 common shares of APUC and bears an interest rate of 0% thereafter.

The Final Instalment Date was established as February 2, 2017, at which time APUC received the Final Instalment payment and concurrently issued 98,022,082 of its common shares as a result of the conversion of $1,039.0 million of debentures to equity. The net proceeds from the Final Instalment of $744.1 million were used to repay a portion of APUC's Acquisition Facility. Subsequent to the Final Instalment Date, an additional 9,495,813 common shares were issued as a result of an additional $100.7 million debentures converting to equity. As of March 1, 2017, $10.3 million of convertible debentures remain outstanding bearing an interest rate of 0%.

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, 2016, APUC had outstanding:


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


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


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

APUC has a shareholder dividend reinvestment plan (the “Reinvestment Plan”) for registered holders of common shares of APUC. As at December 31, 2016, 61,419,484 common shares representing approximately 22% of total common shares outstanding had been registered with the Reinvestment Plan. During the quarter ended December 31, 2016, 725,171 common shares were issued under the Reinvestment Plan, and subsequent to the end of the quarter, on January 13, 2017, an additional 823,738 common shares were issued under the Reinvestment Plan.

SHARE BASED COMPENSATION PLANS

For the twelve months ended December 31, 2016, APUC recorded $5.7 million in total share-based compensation expense as compared to $5.3 million for the same period in 2015. There is no tax benefit associated with the share-based compensation expense. The compensation expense is recorded as part of administrative expenses in the audited consolidated statement of operations. The portion of share-based compensation costs capitalized as cost of construction is insignificant.

As at December 31, 2016, total unrecognized compensation costs related to non-vested options and share unit awards were $3.2 million and $2.2 million, respectively, and are expected to be recognized over a period of 1.77 and 1.74 years, respectively.

Stock Option Plan

APUC has a stock option plan that permits the grant of share options to key officers, directors, employees and selected service providers. Except in certain circumstances, the term of an option shall not exceed ten (10) years from the date of the grant of the option.

APUC determines the fair value of options granted using the Black-Scholes option-pricing model. The estimated fair value of options, including the effect of estimated forfeitures, is recognized as expense on a straight-line basis over the options’ vesting periods while ensuring that the cumulative amount of compensation cost recognized at least equals the value of the vested portion of the award at that date. During the twelve months ended December 31, 2016, the Company granted 2,596,025 options to executives of the Company. The options allow for the purchase of common shares at a weighted average price of $10.86, the market price of the underlying common share at the date of grant. In March 2016, executives of the Company exercised 3,715,663 stock options at a weighted average exercise price of $5.25 in exchange for 2,720,980 common shares issued from treasury and 994,683 shares withheld as payment in lieu of minimum tax withholdings.

As at December 31, 2016, a total of 6,045,014 options are issued and outstanding under the plan.



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Algonquin Power & Utilities Corp. - Management Commentary

Performance Share Units

APUC issues performance share units (“PSUs”) to certain members of management other than senior executives as part of APUC’s long-term incentive program. During the twelve months ended December 31, 2016, the Company granted (including dividends) 219,315 PSUs to executives and employees of the Company. During the year the Company settled 181,875 PSUs by issuing 91,280 shares from treasury, with the balance withheld as payment in lieu of minimum tax withholdings.

As at December 31, 2016, a total of 578,988 PSUs are granted and outstanding under the PSU plan.

Directors Deferred Share Units

APUC has a Directors' Deferred Share Unit Plan. Under the plan, non-employee directors of APUC receive 50% of their annual compensation in deferred share units (“DSUs”) and may elect to receive any portion of their remaining compensation in DSUs. The DSUs provide for settlement in cash or shares at the election of APUC. As APUC does not expect to settle the DSUs in cash, these DSUs are accounted for as equity awards. During the twelve months ended December 31, 2016, the Company issued 67,192 DSUs to the directors of the Company.

As at December 31, 2016, a total of 224,663 DSUs had been granted under the DSU plan.

Employee Share Purchase Plan

APUC has an Employee Share Purchase Plan (the “ESPP”) which allows eligible employees to use a portion of their earnings to purchase common shares of APUC. The aggregate number of shares reserved for issuance from treasury by APUC under this plan shall not exceed 2,000,000 shares. During the twelve months ended December 31, 2016, the Company issued 144,264 common shares to employees under the ESPP.

As at December 31, 2016, a total of 496,030 shares had been issued under the ESPP.

MANAGEMENT OF CAPITAL STRUCTURE

APUC views its capital structure in terms of its debt and equity levels at its individual operating groups and at an overall company level.

APUC’s objectives when managing capital are:


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


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


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


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


•	To maintain sufficient cash reserves on hand to ensure sustainable dividends made to shareholders; and


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

APUC monitors its cash position on a regular basis to ensure funds are available to meet current normal as well as capital and other expenditures. In addition, APUC continuously reviews its capital structure to ensure its individual business groups are using a capital structure which is appropriate for their respective industries.

RELATED PARTY TRANSACTIONS

Emera Inc.

A member of the Board of APUC is an executive at Emera. During 2016, the Energy Services Business sold electricity to Maine Public Service Company, and Bangor Hydro subsidiaries of Emera, amounting to U.S. $10.2 million as compared to U.S. $6.7 million during the same period in 2015. During 2016, Liberty Utilities purchased natural gas amounting to U.S. $3.9 million as compared to U.S. $2.3 million during the same period in 2015 from Emera for its gas utility customers. Both the sale of electricity to Emera and the purchase of natural gas from Emera followed a public tender process the results of which were approved by the regulator in the relevant jurisdiction. On May 13, 2016, a subsidiary of the Company and Emera Utility Services Inc. entered into a design, engineering, supply and construction agreement for the Tinker transmission upgrade project. The total cost of the contract is estimated at $8.8 million and is expected to be completed in 2017. The contract followed a market based request for proposal process. On October 14, 2016, APUC paid $0.7 million to Emera as reimbursement for professional services incurred and accrued in 2014.



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Algonquin Power & Utilities Corp. - Management Commentary

There was U.S. $0.8 million included in accruals in 2016 as compared to U.S. $0.5 million during the same period in 2015, related to these transactions at the end of the year.

Equity-method investments

The Company provides administrative services to its equity-method investees and is reimbursed for incurred costs. To that effect, the Company charged its equity-method investees $3.3 million as compared to $2.0 million during the same period in 2015.

Trafalgar

The Company owned debt on seven hydroelectric facilities owned by Trafalgar Power Inc. and an affiliate ("Trafalgar"). In 1997, Trafalgar went into default under its debt obligations and an entity partially and indirectly owned by Senior Executives (the "Related Entity"), moved to foreclose on the assets on behalf of the Company. Subsequent to the foreclosure action, Trafalgar went into bankruptcy. APUC and the Related Entity have jointly pursued litigation and bankruptcy proceedings with Trafalgar since 2002.

In 2003 and 2004, the Company reimbursed the Related Entity $1.0 million of the approximately $2.0 million in third-party legal fees it had initially funded and APUC agreed to fund future legal fees and other liabilities. It was agreed that any net proceeds from the litigation and bankruptcy proceedings would be shared proportionally to the quantum of net legal costs funded by each party.

On June 30, 2016, the Company received U.S. $10.1 million in proceeds from the settlement of this matter and, subsequent to quarter-end, paid U.S. $2.9 million to the Related Entity as its proportionate share. The gain to APUC, net of legal and other liabilities, of approximately U.S. $6.6 million was recorded in the second quarter of 2016.

The above related party transactions have been recorded at the exchange amounts agreed to by the parties to the transactions.



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Algonquin Power & Utilities Corp. - Management Commentary