EX-99.2 3 a2017q1-exhibit993xmda.htm EXHIBIT 99.2 2017 Q1 MD&A

Exhibit

Management Discussion & Analysis

(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 discussion and analysis to provide information to assist its shareholders’ understanding of the financial results for the three months ended March 31, 2017. The Management Discussion & Analysis (“MD&A”) should be read in conjunction with APUC’s Unaudited Interim Consolidated Financial Statements for the three months ended March 31, 2017 and 2016. The MD&A should also be read in conjunction with APUC's Annual Audited Consolidated Financial Statements for the years ended December 31, 2016 and 2015, and the annual MD&A for the year ended December 31, 2016. This material is available on SEDAR at www.sedar.com and on the APUC website at www.AlgonquinPowerandUtilities.com. Additional information about APUC, including the most recent Annual Information Form (“AIF”) can be found on SEDAR at www.sedar.com.

This MD&A is based on information available to management as of May 11, 2017.

Caution Concerning Forward-looking Statements, Forward-looking Information and non-GAAP Measures

Forward-looking Statements and Forward-looking Information

This MD&A may contain statements that, to the extent that they are not recitations of historical fact, constitute "forward-looking statements" or "forward-looking information" and within the meaning of applicable securities legislation, including the United States Securities Act of 1933, as amended, the United States Securities Exchange Act of 1934, as amended, and applicable Canadian Securities legislation (collectively referred to herein as “forward-looking information” or “forward-looking statements”). All forward-looking information and forward-looking statements are given pursuant to the “safe harbour” provisions of applicable securities legislation. 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 MD&A 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 MD&A. The terms “Adjusted Net Earnings”, “Adjusted Funds from Operations”, "Adjusted EBITDA", "Net Energy Sales", "Net Utility Sales" and "Divisional Operating Profit" are not recognized measures under GAAP. There is no standardized measure of “Adjusted Net Earnings”, "Adjusted EBITDA", “Adjusted Funds from Operations”, "Net Energy Sales", "Net Utility Sales", and "Divisional Operating Profit"; consequently, APUC’s method of calculating these measures may differ from methods used by other companies and therefore may not be comparable to similar measures presented by other companies. A calculation and analysis of “Adjusted Net Earnings”, "Adjusted EBITDA", “Adjusted Funds from Operations”, "Net Energy Sales", "Net Utility Sales", and "Divisional Operating Profit" can be found throughout this MD&A.

Q1 2017 Report	1
Algonquin Power & Utilities Corp. - Management Discussion & Analysis

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. 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. 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

Q1 2017 Report	2
Algonquin Power & Utilities Corp. - Management Discussion & Analysis

may be non-cash, unusual in nature and are not factors used by management for evaluating the operating performance of the divisional units. Divisional Operating Profit is calculated inclusive of Hypothetical Liquidation at Book Value (“HLBV”) income, which represents the value of net tax attributes earned in the period from electricity generated by certain of its U.S. wind power and U.S. solar generation facilities. APUC believes that presentation of this measure will enhance an investor’s understanding of APUC’s divisional operating performance. Divisional Operating Profit is not intended to be representative of cash provided by operating activities or results of operations determined in accordance with 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 flows 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 the Bank of Canada's daily exchange rate as at May 10, 2017, the quarterly dividend is equivalent to Cdn $0.1593 per common share or Cdn $0.6371 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 Liberty Power 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.

Liberty Power Group

The Liberty Power Group generates and sells electrical energy produced by its diverse portfolio of non-regulated renewable power generation and clean energy power generation facilities located across North America. The Liberty Power Group seeks to deliver continuing growth through development of new greenfield power generation projects and accretive acquisitions of additional electrical energy generation facilities.

The Liberty Power Group owns or has interests in hydroelectric, wind, solar, and thermal facilities with a combined generating capacity of approximately 120 MW, 1,050 MW, 40 MWac, 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 Liberty Power 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 a diversified portfolio of regulated utility systems throughout the United States. Liberty Utilities provides safe, high quality, and reliable services to its customers and delivers stable and predictable earnings to APUC. In addition to encouraging and supporting organic growth within its service territories, Liberty Utilities 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 780,000 customers.

The Liberty Utilities Group's regulated electrical distribution utility systems and related generation assets are located in the States of California, New Hampshire, Missouri, Kansas, Oklahoma and Arkansas. The electric utility systems in total serve approximately 263,000 electric connections and operate a fleet of generation assets with a net capacity of 1,424 MW.

The Liberty Utilities Group's regulated natural gas distribution utility systems are located in the States of Georgia, Illinois, Iowa, Massachusetts, New Hampshire and Missouri serving approximately 335,000 natural gas connections.

Q1 2017 Report	3
Algonquin Power & Utilities Corp. - Management Discussion & Analysis

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 which together serve approximately 182,000 connections.

2017 Major Highlights

Corporate Highlights

Completion of The Empire District Electric Company Acquisition

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. $2.414 billion ("Empire Acquisition").

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 Empire Acquisition, APUC has materially expanded its utility operations in the U.S.. APUC, through its 2,200 employees, now serves over 780,000 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 generating capacity of over 2,500 MW.

Accretion of Empire in First Quarter Operating Results

APUC recorded a strong three months of operations results relative to the same period last year primarily as a result of the acquisition of Empire.

(all dollar amounts in $ millions except per share information)	Three Months Ended March 31
	2017				2016				Change
Net earnings attributable to shareholders 1	$	26.0			$	42.0			(38	)%
Adjusted Net Earnings	$	88.1			$	56.1			57	%
Adjusted EBITDA	$	254.8			$	147.9			72	%
Net earnings per common share	$	0.07			$	0.15			(53	)%
Adjusted Net Earnings per common share	$	0.25			$	0.21			19	%
1 Includes $60.4 million of Acquisition Related Costs expensed in the first quarter of 2017 as compared to $6.3 million in 2016

Completion of Financing Related to the Acquisition of Empire

$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 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. As at May 10, 2017, approximately 99.6% representing $1.146 billion of the Debentures have been converted into 108,075,037 common shares of APUC. 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 24, 2017, Liberty Utilities through its financing entity issued U.S. $750.0 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 an effective interest rate of 3.6% (inclusive of interest rate hedges).

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

Declaration of Canadian Equivalent Second Quarter Dividend of Cdn $0.1593 (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 an attractive current dividend yield and capital appreciation.

Q1 2017 Report	4
Algonquin Power & Utilities Corp. - Management Discussion & Analysis

In addition to the completion of the Empire Acquisition in the first quarter of 2017, APUC 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.

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

	Q3 2016				Q4 2016				Q1 2017				Q2 2017				Total
U.S. dollar dividend	$	0.1059			$	0.1059			$	0.1165			$	0.1165			$	0.4448
Canadian dollar equivalent	$	0.1377			$	0.1427			$	0.1533			$	0.1593			$	0.5930

Liberty Power Group Highlights

Completion of the Deerfield Wind Project

On February 21, 2017, the Deerfield Wind Facility achieved commercial operations ("COD"). The project consists of a 150 MW wind generating facility located in central Michigan. On May 10, 2017, tax equity financing of approximately U.S. $166.6 million was completed. The Deerfield Wind Facility is the Liberty Power 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 Power Purchase Agreement ("PPA") with an investment grade local electric distribution utility serving approximately 260,000 customers in Michigan.

Completion of the Bakersfield II Solar Project

On January 11, 2017, the Liberty Power 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. $12.3 million was completed. The Bakersfield II Solar Facility is the Liberty Power 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.

Issuance of $300 million Senior Unsecured Debentures

On January 17, 2017 the Liberty Power 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 Liberty Power Group entered into a cross currency swap, coterminous with the debentures, to economically convert the Canadian dollar denominated offering into U.S. dollars.

The net proceeds were used to partially finance the Odell Wind, Deerfield Wind and Bakersfield II Solar projects.

Liberty Utilities Group Highlights

Completion of the Luning Solar Project.

On February 15, 2017, the Liberty Utilities Group obtained control of a 50 MWac 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.

Q1 2017 Report	5
Algonquin Power & Utilities Corp. - Management Discussion & Analysis

2017 First Quarter Results From Operations

Key Financial Information	Three Months Ended March 31
(all dollar amounts in $ millions except per share information)	2017				2016
Revenue	$	557.9			$	341.7
Net earnings attributable to shareholders	26.0				42.0
Cash provided by operating activities	83.8				53.4
Adjusted Net Earnings1	88.1				56.1
Adjusted EBITDA1	254.8				147.9
Adjusted Funds from Operations1	208.9				121.8
Dividends declared to common shareholders	59.4				35.0
Weighted average number of common shares outstanding	343,549,831				268,565,782
Per share
Basic net earnings	$	0.07			$	0.15
Diluted net earnings	$	0.07			$	0.14
Adjusted Net Earnings1,2	$	0.25			$	0.21
Dividends declared to common shareholders	$	0.15			$	0.13
	As at
	March 31, 2017				December 31, 2016
Total Assets	$	10,880.7			$	8,249.5
Long term debt3	$	4,773.6			$	4,272.0

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 three months ended March 31, 2017, APUC experienced an average U.S. exchange rate of approximately 1.3229 as compared to 1.3741 in the same period in 2016. 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 March 31, 2017, APUC reported total revenue of $557.9 million as compared to $341.7 million during the same period in 2016, an increase of $216.2 million. The major factors resulting in the increase in APUC revenue in the three months ended March 31, 2017 as compared to the corresponding period in 2016 are set out as follows:

Q1 2017 Report	6
Algonquin Power & Utilities Corp. - Management Discussion & Analysis

(all dollar amounts in $ millions)	Three Months Ended March 31
Comparative Prior Period Revenue	$	341.7
LIBERTY POWER GROUP
Existing Facilities
Hydro: Decrease is primarily due to the recognition of the global adjustment from the Ontario Energy Finance Corporation ("OEFC") in 2016 as well as decreased production, partially offset by annual PPA rate increases.	(1.9		)
Wind Canada: Increase is largely due to increased production and annual rate increases.	0.5
Wind U.S.: Decrease is primarily due to fewer REC sales as compared to the prior year.	(1.1		)
Solar U.S.: Decrease is primarily due to business interruption insurance proceeds received in the prior year in excess of current year production.	(0.5		)
Thermal: Increase was due to higher fuel prices realized at the Windsor Lock Thermal Facility and rising REC prices, partially offset by the decrease in production at Sanger.	0.8
Other: Decrease was primarily caused by the shutdown of the hydro mulch business at Sanger.	(0.7		)
	(2.9		)
New Facilities
Wind U.S.: Acquisition of Odell (Sept 2016) and Deerfield (Feb 2017) Wind facilities.	8.6
Solar U.S.: Bakersfield II was placed in service in Dec 2016.	0.3
	8.9
Foreign Exchange	(1.7		)
LIBERTY UTILITIES GROUP
Existing Facilities
Electricity: Decrease was primarily due to lower commodity pass-through costs at the Granite State and CalPeco Electric Systems.	(7.8		)
Gas: Increase was primarily due to increased pass-through costs at the EnergyNorth and New England Gas systems as it relates to higher customer demand, partially offset by warmer weather in the Midstates Gas System.	14.5
Water: Increase is primarily due to increased usage at the Park Water System.	0.8
Other	0.3
	7.8
New Facilities
Electricity: Acquisition of Empire's electric distribution systems on January 1, 2017.	181.9
Gas: Acquisition of Empire's gas distribution system on January 1, 2017.	18.2
Water: Acquisition of Empire's water distribution system on January 1, 2017.	0.7
Other: Acquisition of Empire's fiber optic operations on January 1, 2017.	2.5
	203.3
Rate Cases
Electricity: Implementation of new rates at the CalPeco Electric system and interim rates at the Granite State Electric system.	5.1
Gas: Implementation of new rates at the Peach State, Missouri, Iowa and New England Gas systems.	6.2
Water: Implementation of new rates at the Rio Rico and Bella Vista water systems.	0.5
	11.8
Foreign Exchange	(11.0		)
Current Period Revenue	$	557.9

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

For the three months ended March 31, 2017, net earnings attributable to shareholders totaled $26.0 million as compared to $42.0 million during the same period in 2016, a decrease of $16.0 million or 38.1%. The decrease was primarily due to a $54.1 million increase in acquisition related costs due to the acquisition of Empire as compared to the same period in 2016. Other factors affecting changes to net earnings were a $3.2 million increase in administration charges, $33.0 million increase in depreciation and amortization expenses, $39.5 million increase in interest expense, $1.2 million decrease in other

Q1 2017 Report	7
Algonquin Power & Utilities Corp. - Management Discussion & Analysis

gains, $0.4 million decrease in foreign exchange gain, $0.9 million increase in income tax expense (tax explanations are discussed in APUC: Corporate and Other Expenses), and $0.5 million increase in losses from derivative instruments. These items were partially offset by a $101.1 million increase in earnings from operating facilities (including Empire), $0.7 million increase in interest, dividend, equity and other income, $8.8 million increase in losses attributable to non-controlling interests, and a $6.2 million decrease in losses on long lived assets.

During the three months ended March 31, 2017, cash provided by operating activities totaled $83.8 million as compared to cash provided by operating activities of $53.4 million during the same period in 2016. During the three months ended March 31, 2017, Adjusted Funds from Operations totaled $208.9 million compared to Adjusted Funds from Operations of $121.8 million during the same period in 2016. The change in Adjusted Funds from Operations in the three months ended March 31, 2017 is primarily due to increased earnings from operations (including Empire) as compared to the same period in 2016.

During the three months ended March 31, 2017 Adjusted EBITDA totaled $254.8 million as compared to $147.9 million during the same period in 2016, an increase of $106.9 million or 72.3%. 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).

2017 Adjusted EBITDA Summary

Adjusted EBITDA in the three months ended March 31, 2017 totaled $254.8 million as compared to $147.9 million during the same period in 2016, an increase of 106.9 million or 72.3%. The breakdown of Adjusted EBITDA (see Non-GAAP Performance Measures) by the company's main operating segments and summaries of changes is shown below.

Adjusted EBITDA by segment	Three Months Ended March 31
(all dollar amounts in $ millions)	2017				2016
Liberty Power Group Operating Profit	$	70.1			$	63.4
Liberty Utilities Group Operating Profit	198.6				95.1
Administration Expenses	(14.6		)		(11.4		)
Other Income & Expenses	0.7				0.8
Total Algonquin Power & Utilities Adjusted EBITDA	$	254.8			$	147.9
Change in Adjusted EBITDA ($)	$	106.9
Change in Adjusted EBITDA (%)	72.3		%

Change in Adjusted EBITDA Breakdown
(all dollar amounts in $ millions)	Liberty Power				Liberty Utilities				Corporate				Total
Prior Period Balances	$	63.4			$	95.1			$	(10.6	)		$	147.9
Existing Facilities	(2.9		)		6.0				(0.1		)		3.0
New Facilities	10.6				89.3				—				99.9
Rate Cases	—				11.8				—				11.8
Foreign Exchange Impact	(1.0		)		(3.6		)		—				(4.6		)
Administration Expenses	—				—				(3.2		)		(3.2		)
Total change during the period	$	6.7			$	103.5			$	(3.3	)		$	106.9
Current Period Balances	$	70.1			$	198.6			$	(13.9	)		$	254.8

Q1 2017 Report	8
Algonquin Power & Utilities Corp. - Management Discussion & Analysis

LIBERTY POWER GROUP

2017 Electricity Generation Performance
	Long Term Average Resource			Three Months Ended March 31
(Performance in GW-hrs sold)				2017			2016
Hydro Facilities:
Maritime Region	27.5			34.4			47.7
Quebec Region	56.0			61.6			73.8
Ontario Region	36.0			35.0			40.3
Western Region	9.6			10.2			10.8
	129.1			141.2			172.6
Wind Facilities:
St. Damase	20.9			21.0			22.5
St. Leon	121.4			113.1			91.0
Red Lily1	23.2			23.7			18.5
Morse	30.5			25.4			21.9
Sandy Ridge	47.1			50.8			49.1
Minonk	200.6			206.4			209.4
Senate	151.3			148.4			153.4
Shady Oaks	108.2			110.5			97.6
Odell2	230.5			231.3			—
Deerfield3	75.8			73.7			—
	1,009.5			1,004.3			663.4
Solar Facilities:
Cornwall	2.6			2.5			2.5
Bakersfield I	9.1			8.7			7.9
Bakersfield II4	3.8			3.9			—
	15.5			15.1			10.4
Renewable Energy Performance	1,154.1			1,160.6			846.4
Thermal Facilities:
Windsor Locks	N/A5			30.0			28.2
Sanger	N/A5			15.1			32.0
				45.1			60.2
Total Performance				1,205.7			906.6

1	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 is accounted for using the equity method. The production figures represent full energy produced by the facility.
2	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.
3	The Deerfield Wind Facility achieved COD on February 21, 2017 and was treated as an equity investment until March 14, 2017 at which time the Company acquired the remaining 50% ownership in the facility. The LTAR and production noted above represents all production from the date of COD.
4	The Bakersfield II Solar Facility achieved COD on January 11, 2017 in accordance with the terms of the PPA. The LTAR and production noted above represents all production from the date of COD.
5	Natural gas fired co-generation facility.

Q1 2017 Report	9
Algonquin Power & Utilities Corp. - Management Discussion & Analysis

2017 First Quarter Liberty Power Performance

For the three months ended March 31, 2017, the Liberty Power Group generated 1,205.7 GW-hrs of electricity as compared to 906.6 GW-hrs during the same period of 2016.

For the three months ended March 31, 2017, the hydro facilities generated 141.2 GW-hrs of electricity as compared to 172.6 GW-hrs produced in the same period in 2016, a decrease of 18.2%. Electricity generated represented 109.4% of long-term average resources ("LTAR") as compared to 131.4% during the same period in 2016. During the quarter, generation in the Maritime, Quebec and Western regions surpassed their respective LTARs.

For the three months ended March 31, 2017, the wind facilities produced 1,004.3 GW-hrs of electricity as compared to 663.4 GW-hrs produced in the same period in 2016, an increase of 51.4%. 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) as well as generation from the new Deerfield Wind Facility. These items were partly offset by lower production at the St. Damase, Minonk and Senate Wind Facilities. During the three months ended March 31, 2017, the wind facilities (excluding the Odell Wind Facility) generated electricity equal to 99.4% of LTAR as compared to 98.5% during the same period in 2016.

For the three months ended March 31, 2017, the solar facilities generated 15.1 GW-hrs of electricity as compared to 10.4 GW-hrs of electricity in the same period in 2016, an increase of 45.2%. The increase in production is largely attributable to the new Bakersfield II Solar Facility. Excluding the new site, Cornwall and Bakersfield had a production increase of 7.7%.

For the three months ended March 31, 2017, the thermal facilities generated 45.1 GW-hrs of electricity as compared to 60.2 GW-hrs of electricity during the same period in 2016. During the same period, the Windsor Locks Thermal Facility generated 166.5 billion lbs of steam as compared to 185.7 billion lbs of steam during the same period in 2016.

2017 Liberty Power Group Operating Results	Three Months Ended March 31
(all dollar amounts in $ millions)	2017				2016
Revenue1
Hydro	$	17.5			$	19.7
Wind	44.1				35.7
Solar	2.2				2.4
Thermal	8.0				7.7
Total Revenue	$	71.8			$	65.5
Less:
Cost of Sales - Energy2	(1.7		)		(1.1		)
Cost of Sales - Thermal	(5.6		)		(4.5		)
Realized loss on hedges3	(0.7		)		(1.0		)
Net Energy Sales	$	63.8			$	58.9
Renewable Energy Credits ("REC")	4.8				6.1
Other Revenue	0.1				0.8
Total Net Revenue	$	68.7			$	65.8
Expenses & Other Income
Operating expenses	(19.2		)		(16.3		)
Interest, dividend, equity and other income	1.2				0.5
HLBV income4	19.4				13.4
Divisional Operating Profit5	$	70.1			$	63.4

1	While most of the Liberty Power Group's PPAs include annual rate increases, a change to the weighted average production levels resulting from higher average production from facilities that earn lower or higher energy rates can result in a different 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 21(b)(iv).
4	HLBV income represents the value of net tax attributes earned by the Liberty Power Group in the period from electricity generated by certain of its U.S. wind power and U.S. solar generation facilities.
5	See Non-GAAP Financial Measures.

Q1 2017 Report	10
Algonquin Power & Utilities Corp. - Management Discussion & Analysis

2017 First Quarter Operating Results

For the three months ended March 31, 2017, the Liberty Power Group facilities generated $70.1 million of operating profit as compared to $63.4 million during the same period in 2016, which represents an increase of $6.7 million, excluding corporate administration expenses.

Highlights of the changes are summarized in the following table:

(all dollar amounts in $ millions)	Three Months Ended March 31
Prior Period Operating Profit	$	63.4
Existing Facilities
Hydro: Decrease largely due to prior year recognition of Global Adjustment payment from the Ontario Energy Finance ("OEFC") in 2016 as well as a decline in production compared to the previous year. In the Maritime region the decreased production necessitated an increase in purchased power to supply retail customers.	(2.2		)
Wind Canada: Increase is largely due to increased production and annual rate increases.	0.4
Wind U.S.: Increase is primarily due to higher production at the Shady Oaks Wind Facility, and HLBV income, partially offset by lower REC revenues.	0.7
Solar U.S.: Decrease is primarily due to business interruption insurance proceeds received in the prior year in excess of current year operating profit.	(0.5		)
Thermal: Decrease is primarily due to higher commodity costs at the thermal facilities, partially offset by higher REC sales at the Windsor Locks Thermal Facility.	(0.3		)
Other: Decrease was primarily due to the permanent shutdown of the hydro mulch business at the Sanger Thermal Facility.	(1.0		)
	(2.9		)
New Facilities
Wind U.S.: Acquisition of Odell and Deerfield Wind facilities.	10.3
Solar U.S.: Bakersfield II was placed in service in Dec 2016.	0.3
	10.6
Foreign Exchange	(1.0		)
Current Period Divisional Operating Profit	$	70.1

Q1 2017 Report	11
Algonquin Power & Utilities Corp. - Management Discussion & Analysis

Development Division

The Liberty Power Group’s Development Division is focused on developing, contracting, and transitioning recently completed projects to the operations group. 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 satisfy 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	193			2017	10	146
Total Projects in Construction		150	$	488				381
Projects in Development
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	$	898				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 MW wind powered electric generating project located in central Michigan with land control over approximately 20,000 acres of land.

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

The project is the Liberty Power 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 Wolverine Power Supply Cooperative, a local electric distribution utility, which serves 260,000 customers in Michigan, pursuant to a 20 year PPA. The facility achieved COD on February 21, 2017.

The Liberty Power Group's initial interest in the project was via a 50% joint venture with the original developer along with an option to acquire the other 50% interest. On March 14, 2017, the Liberty Power Group exercised its option and purchased the remaining 50% interest in the project for U.S. $21.6 million.

The project qualifies for U.S. federal production tax credits, and consistent with financing structures utilized for U.S. based renewable energy projects approximately U.S. $166.6 million of financing for the project was sourced from tax equity investors.

Bakersfield II Solar Project

The Bakersfield II Solar Project is a 10 MWac solar powered electric generating project adjacent to the Liberty Power Group's 20 MWac 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 Liberty Power 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. $12.3 million of financing for the project was sourced from tax equity investors. The tax equity financing closed on February 28, 2017 following achievement of commercial operations.

Q1 2017 Report	12
Algonquin Power & Utilities Corp. - Management Discussion & Analysis

Projects in Construction

Amherst Island Wind Project

The Amherst Island Wind Project is a 75 MW wind powered electric generating development project located on Amherst Island near the village of Stella, approximately 15 kilometers southwest of Kingston, Ontario.

The Renewable Energy Approval ("REA") for the project 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. A Divisional Court challenge of the favorable ERT decision was dismissed in the first quarter of 2017.

Construction is underway and progressing according to schedule. The Company has procured the project turbines, submarine cable, and the main power transformer. The balance of plant constructor has also been engaged. Subject to receipt of final permits and negotiation of remaining agreements, construction is expected to be complete in the second quarter of 2018.

Great Bay Solar

The Great Bay Solar Project is a 75 MWac solar powered electric generating development project located in Somerset County in southern Maryland.

The facility is composed 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.

The project has received its Certificate of Public Convenience and Necessity from the State of Maryland Public Service Commission and building permits from the Somerset County Building and Zoning Department. Both the balance of plant and high voltage engineering, procurement, and construction contracts have been executed, and project construction has commenced. 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 Liberty Power Group expects the project will qualify for U.S. federal investment tax credits and accordingly, has selected a tax equity investor to provide approximately 40% of the permanent project financing in return for the majority of the tax attributes.

Projects in Development

Blue Hill Wind Project

The Blue Hill Wind Project is a 177 MW wind powered electric generating development project located in the rural municipality of Lawtonia in southwest Saskatchewan. All of the energy from the project will be sold to SaskPower pursuant to a 25 year PPA originally awarded in 2012. The project requires final environmental approval and all other necessary permitting. SaskPower is currently completing a system impact study for the wind turbine generators, and environmental field studies are in progress.

Q1 2017 Report	13
Algonquin Power & Utilities Corp. - Management Discussion & Analysis

LIBERTY UTILITIES GROUP

The Liberty Utilities Group operates rate-regulated utilities that provide distribution services to approximately 780,000 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. The Liberty Utilities Group's strategy is to grow its business organically and through business development activities while using prudent acquisition criteria.  The Liberty Utilities Group believes that its business results are maximized by building constructive regulatory and customer relationships, and enhancing connections in the communities in which it operates.

Utility System Type	As at March 31
	2017						2016
(all dollar amounts in U.S. $ millions)	Assets			Total Connections1			Assets			Total Connections1
Electricity	$	2,471.1		263,000			$	346.0		93,000
Natural Gas	917.5			335,000			784.5			293,000
Water and Wastewater	525.8			182,000			498.1			178,000
Total	$	3,914.4		780,000			$	1,628.6		564,000
Accumulated Deferred Income Taxes Liability	$	639.1					$	167.3

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 263,000 connections in the states of California, New Hampshire, Missouri, Kansas, Oklahoma and Arkansas.

The natural gas distribution systems are comprised of regulated natural gas distribution utility systems and serve approximately 335,000 connections located in the states of Georgia, Illinois, Iowa, Massachusetts, New Hampshire and Missouri.

The water and wastewater distribution systems are comprised of regulated water distribution and wastewater collection utility systems and serve approximately 182,000 connections located in the states of Arkansas, Arizona, California, Illinois, Missouri, Montana, and Texas.

2017 First Quarter Usage Results

Electric Distribution Systems	Three Months Ended March 31
	2017			2016
Average Active Electric Connections For The Period
Residential	223,400			80,300
Commercial and industrial	39,000			12,400
Total Average Active Electric Connections For The Period	262,400			92,700
Customer Usage (GW-hrs)
Residential	643.3			165.8
Commercial and industrial	818.5			219.5
Total Customer Usage (GW-hrs)	1,461.8			385.3

For the three months ended March 31, 2017 the electric distribution systems' usage totaled 1,461.8 GW-hrs as compared to 385.3 GW-hrs for the same period in 2016, an increase of 1,076.5 GW-hrs or 279.4%. The addition of Empire accounted for 1,071.8 GW-hrs of the increase. The CalPeco Electric System and Granite State Electric System usage totaled 390.0 GW-hrs, an increase of 4.7 GW-hrs or 1.2%.

Q1 2017 Report	14
Algonquin Power & Utilities Corp. - Management Discussion & Analysis

Natural Gas Distribution Systems	Three Months Ended March 31
	2017			2016
Average Active Natural Gas Connections For The Period
Residential	291,200			252,400
Commercial and industrial	32,200			27,100
Total Average Active Natural Gas Connections For The Period	323,400			279,500
Customer Usage (MMBTU)
Residential	8,445,000			7,870,000
Commercial and industrial	4,842,000			4,837,000
Total Customer Usage (MMBTU)	13,287,000			12,707,000

For the three months ended March 31, 2017, usage at the natural gas distribution systems totaled 13,287,000 MMBTU as compared to 12,707,000 MMBTU during the same period in 2016, an increase of 580,000 MMBTU, or 4.6%. The addition of Empire accounted for 1,390,000 MMBTU of the increase. Excluding the addition of Empire, usage totaled 11,897,000 MMBTU, a decrease of 810,000 MMBTU, or 6.4%. The decrease was primarily due to lower demand and heating degree days in the Midstates and Peach State Gas Systems during the three months ended March 31, 2017 as compared to the same period in the prior year.

Water and Wastewater Distribution Systems	Three Months Ended March 31
	2017			2016
Average Active Connections For The Period
Wastewater connections	40,800			40,200
Water distribution connections	134,800			131,300
Total Average Active Connections For The Period	175,600			171,500
Gallons Provided
Wastewater treated (millions of gallons)	589			598
Water sold (millions of gallons)	3,370			3,066
Total Gallons Provided	3,959			3,664

During the three months ended March 31, 2017, the water and wastewater distribution systems provided approximately 3,370 million gallons of water to its customers and treated approximately 589 million gallons of wastewater as compared to 3,066 million gallons of water provided and 598 million gallons of wastewater treated during the same period in 2016. The increase in the gallons of water provided to customers can be primarily attributed to increased water usage at the Park Water systems in California.

2017 First Quarter Operating Results

	Three Months Ended March 31
	2017 U.S. $ (millions)				2016 U.S. $ (millions)				2017 Can $ (millions)				2016 Can $ (millions)
Revenue
Utility electricity sales and distribution	$	181.5			$	46.1			$	240.1			$	63.4
Less: cost of sales – electricity	(54.6		)		(28.4		)		(72.3		)		(39.2		)
Net Utility Sales - electricity	126.9				17.7				167.8				24.2
Utility natural gas sales and distribution	136.9				109.5				181.2				151.4
Less: cost of sales – natural gas	(61.6		)		(46.7		)		(81.4		)		(64.7		)
Net Utility Sales - natural gas	75.3				62.8				99.8				86.7
Utility water distribution & wastewater treatment sales and distribution	32.4				30.0				42.9				41.1
Less: cost of sales – water	(2.0		)		(2.0		)		(2.7		)		(2.8		)
Net Utility Sales - water distribution & wastewater treatment	30.4				28.0				40.2				38.3
Gas transportation	10.9				9.0				14.5				12.4
Other revenue	1.9				0.8				2.6				1.1
Net Utility Sales	245.4				118.3				324.9				162.7
Operating expenses	(98.0		)		(50.0		)		(129.7		)		(68.8		)
Other income	1.0				1.0				1.3				1.2
HLBV	$	1.6			$	—			$	2.1			$	—
Divisional Operating Profit1	$	150.0			$	69.3			$	198.6			$	95.1

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

For the three months ended March 31, 2017, the Liberty Utilities Group reported an operating profit (excluding corporate administration expenses) of U.S. $150.0 million as compared to U.S. $69.3 million for the comparable period in the prior year. Measured in Canadian dollars, the group's operating profit was $198.6 million as compared to $95.1 million during the same period in 2016, which represents an increase of $103.5 million or 109%, excluding corporate administration expenses.

Q1 2017 Report	15
Algonquin Power & Utilities Corp. - Management Discussion & Analysis

Highlights of the changes are summarized in the following table:

(all dollar amounts in $ millions)	Three Months Ended March 31
Prior Period Operating Profit	$	95.1
Existing Facilities
Electricity: Increase is primarily due to lower operating costs at the CalPeco and Granite State Electric systems.	1.7
Gas: Increase is primarily due to higher demand and colder weather conditions at the EnergyNorth Gas System. Usage at the Midstates and Georgia Gas Systems were lower as compared to the prior year, however, operating profit was consistent due decoupling measures implemented at these utilities.	3.7
Water: Increase is primarily due to increased usage at the Park Water System.	0.5
Other	0.1
	6.0
New Facilities
Electricity: Acquisition of Empire on January 1, 2017. In the first quarter Empire's electric operations experienced lower than normal heating degree days which resulted in a negative operating profit variance of U.S. $11.7 million.	81.3
Gas: Acquisition of Empire on January 1, 2017. In the first quarter Empire's gas operations experienced lower than normal heating degree days which resulted in a negative operating profit variance of U.S $2.7 million	5.1
Water: Acquisition of Empire on January 1, 2017.	0.2
Other: Acquisition of Empire's fiber optic operations on January 1, 2017.	2.7
	89.3
Rate Cases
Electricity: Implementation of new rates at the CalPeco Electric System due to the general rate case and inclusion of the Luning Solar Facility in rate base, as well as interim rates at the Granite State Electric System.	5.1
Gas: Implementation of new rates at the Peach State, Missouri, Iowa and New England Gas systems.	6.2
Water: Implementation of new rates at the Rio Rico and Bella Vista water systems.	0.5
	11.8
Foreign Exchange	(3.6		)
Current Period Divisional Operating Profit	$	198.6

Q1 2017 Report	16
Algonquin Power & Utilities Corp. - Management Discussion & Analysis

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
Granite State Electric System	New Hampshire	General Rate Case	$7.7	Final Order issued in April 2017 approving a U.S. $6.2 million rate increase effective May 1, 2017, and two additional annual increases of U.S. $0.2 million to U.S.$0.3 million effective May 1, 2018 and May 1, 2019.
New England Gas	Massachusetts	Gas System Enhancement Plan (GSEP)	$3.8	Final Order issued in April 2017 approving a U.S. $2.9 million rate increase effective May 1, 2017.
Iowa Gas System	Iowa	General Rate Case	$1.1	Final Order issued in April 2017 approving a U.S. $1.0 million rate increase effective either June or July 2017.
Peach State Gas System	Georgia	Gas Rate Adjustment Mechanism	$0.7	Final Order issued in February 2017 approving a U.S. $0.7 million rate increase effective February 1, 2017.
Entrada Del Oro	Arizona	General Rate Case	$0.3	Final Order issued in March 2017 approving a U.S. $0.2 million rate increase effective April 1, 2017.
Pending Rate Cases
EnergyNorth Gas System	New Hampshire	General Rate Case	$19.9	On April 27, 2017, filed an application seeking an increase of U.S. $13.8 million, plus a step increase of U.S. $6.1 million to be implemented in June 2018. Temporary rates of U.S. $7.8 million were requested to be effective as of July 1, 2017.
Litchfield Park Water & Sewer	Arizona	General Rate Case	$5.1	On February 28, 2017, filed a water/sewer rate application (test year December 31, 2016) seeking an increase of U.S. $5.1 million in rates. New rates are expected to be effective Q1 2018.
CalPeco Electric	California	Turquoise Solar Project	$3.5	On December 14, 2016, filed an application seeking approval to include the 10 MWac Turquoise Solar Project into rate base as of January 1, 2018 through Post Test-Year Adjustment Mechanism (“PTAM”) scheduled to be filed October 2017.
Illinois Gas System	Illinois	General Rate Case	$3.0	Final hearing concluded in March 2017 approving a U.S. $2.2 million rate increase for rates effective July 1 2017. Order is expected to be issued in June 2017.
Oklahoma Electricity System	Oklahoma	General Rate Case	$3.0	On December 21, 2016, filed an application seeking incremental revenues of U.S. $3.8 million (revised to U.S. $3.0 million). Approvals expected by July 2017, with rates effective August 2017. Interim rates may be implemented in July 2017.
Woodmark/Tall Timbers Water & Wastewater Systems	Texas	General Rate Case	$2.0	On September 6, 2016, filed an application seeking a U.S. $2.0 million revenue increase. A final decision is expected in Q4 2017.
Kansas Asbury Environmental and Riverton Cost Recovery (“AERR”) Rider	Kansas	Rate Rider Recovery	$1.9	On January 6, 2017, filed an applications in Kansas for the Asbury Environmental and Riverton Cost Recovery (“AERR”) Rider seeking an incremental revenue increase of U.S. $1.9 million. The revised rider rates are expected to be implemented by no later than September 2017.
New England Gas	Massachusetts	Decoupling Filing	$0.2	On February 1, 2017, filed a revenue decoupling filing with the Massachusetts Department of Public Utilities (“MDPU”) seeking a recovery for reconciliation of 2016 off-peak period (May – October) which would allow for U.S. $0.2 million incremental revenue increase. New rates are expected to take effect May 1, 2017.

Q1 2017 Report	17
Algonquin Power & Utilities Corp. - Management Discussion & Analysis

Completed Rate Cases

On April 29, 2016, the Granite State Electric System filed a rate application. The application sought a U.S. $5.3 million annual revenue increase proposed for effect July 1, 2016, 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. In April 2017 an Order was issued by the New Hampshire Public Utilities Commission approving a U.S. $3.8 million increase to annual distribution revenues along with an annual increase of U.S. $2.5 million for the revenue requirement associated with 2016 capital investment, both effective May 1, 2017 (achieving 82% of the requested increase). The difference between the U.S. $3.8 million permanent increase and the U.S. $2.4 million temporary rate level that was in effect since July 1, 2016 will be collected beginning May 1, 2017. The settlement also provides for two additional annual increases of approximately U.S. $0.3 million effective May 1, 2018 and May 1, 2019 to recover the revenue requirement associated with certain significant capital investments made during the prior calendar year. The rates are based on a return on equity ("ROE") of 9.4% and 50.0% equity.

In October 2016, the New England Natural Gas System filed its Gas System Enhancement Plan (GSEP) application seeking incremental revenue requirement of U.S. $3.8 million for an effective date of May 1, 2017. The Order was issued in April 2017 approving a revenue requirement of U.S. $2.9 million, effective May 1, 2017, to recover costs over the period of May 1, 2017 to April 30, 2018. The Company’s GSEP filing outlined a 4-year replacement plan, in which the Company anticipates replacing 14 miles of aging infrastructure along with the replacement and/or transfer of 983 gas services.

APUC: CORPORATE AND OTHER EXPENSES

	Three Months Ended March 31
(all dollar amounts in $ millions)	2017				2016
Corporate and other expenses:
Administrative expenses	$	14.6			$	11.4
Loss (gain) on foreign exchange	0.1				(0.3		)
Interest expense on convertible debentures and acquisition facility due to the acquisition of Empire	17.6				5.9
Interest expense	46.9				19.2
Interest, dividend, equity, and other income1	(0.7		)		(0.9		)
Other losses2	—				5.0
Acquisition-related costs	60.4				6.3
Loss on derivative financial instruments	1.4				0.9
Income tax expense	19.4				18.5

1	Excludes income directly pertaining to the Liberty Power and Liberty Utilities Groups (disclosed in the relevant sections).
2	Includes Other Gains and Loss on long-lived assets, net per the Statement of Operations.

2017 First Quarter Corporate and Other Expenses

During the three months ended March 31, 2017, administrative expenses totaled $14.6 million as compared to $11.4 million in the same period in 2016. The $3.2 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 March 31, 2017, interest expense on convertible debentures and acquisition financing totaled $17.6 million. (See Convertible Unsecured Subordinated Debentures and note 10 in the Unaudited Interim Consolidated Financial Statements.)

For the three months ended March 31, 2017, interest expense totaled $46.9 million as compared to $19.2 million in the same period in 2016. The increase is primarily attributable to assumed and incremental Empire Acquisition debt, and new debt raised at Liberty Power. (See Credit Facilities & Debt and note 7 in the Unaudited Interim Consolidated Financial Statements.)

For the three months ended March 31, 2017 other losses were $nil as compared to a loss of $5.0 million in the same period in 2016. The prior period loss is primarily due to the write off of the Company's equity interest in transmission development projects.

Q1 2017 Report	18
Algonquin Power & Utilities Corp. - Management Discussion & Analysis

For the three months ended March 31, 2017, acquisition-related costs totaled $60.4 million as compared to $6.3 million in the same period in 2016. The increase is primarily attributable to the Empire Acquisition.

For the three months ended March 31, 2017, loss on derivative financial instruments totaled $1.4 million as compared to $0.9 million in the same period in 2016.

For the three months ended March 31, 2017, income tax expense of $19.4 million was recorded as compared to income tax expense of $18.5 million during the same period in 2016. The increase in income tax expense is primarily due to the impact of the acquisition of Empire and increased HLBV earnings offset by the impact of additional interest expense.

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 unaudited interim consolidated statements 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.

	Three Months Ended March 31
(all dollar amounts in $ millions)	2017				2016
Net earnings attributable to shareholders	$	26.0			$	42.0
Add (deduct):
Net earnings attributable to the non-controlling interest, exclusive of HLBV	1.0				1.7
Income tax expense	19.4				18.5
Interest expense on convertible debentures and acquisition financing	17.6				5.9
Interest expense on long-term debt and others	46.9				19.2
Other gains	—				(1.2		)
Loss on long-lived assets, net	—				6.2
Acquisition-related costs	60.4				6.3
Loss on derivative financial instruments	1.4				0.9
Realized gain on energy derivative contracts	(0.7		)		(1.0		)
Loss (gain) on foreign exchange	0.1				(0.3		)
Depreciation and amortization	82.7				49.7
Adjusted EBITDA	$	254.8			$	147.9

HLBV represents the value of net tax attributes earned during the period from electricity generated by certain of its U.S. wind power and U.S. solar generation facilities. HLBV earned in the three months ended March 31, 2017 amounted to $21.5 million.

Q1 2017 Report	19
Algonquin Power & Utilities Corp. - Management Discussion & Analysis

Reconciliation of Adjusted Net Earnings to Net Earnings

The following table is derived from and should be read in conjunction with the unaudited interim consolidated statements 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 March 31
(all dollar amounts in $ millions)	2017				2016
Net earnings attributable to shareholders	$	26.0			$	42.0
Add (deduct):
Loss on derivative financial instruments	1.4				0.9
Realized gain on derivative financial instruments	(0.7		)		(1.0		)
Loss on long-lived assets, net	—				6.2
Loss (gain) on foreign exchange	0.1				(0.3		)
Interest expense on convertible debentures and acquisition financing	17.6				5.9
Acquisition-related costs	60.4				6.3
Adjustment for taxes	(16.7		)		(3.9		)
Adjusted Net Earnings	$	88.1			$	56.1
Adjusted Net Earnings per share1	$	0.25			$	0.21

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 March 31, 2017, Adjusted Net Earnings totaled $88.1 million as compared to Adjusted Net Earnings of $56.1 million, an increase of $32.0 million as compared to the same period in 2016. The increase in Adjusted Net Earnings for the three months ended March 31, 2017 is primarily due to increased earnings from operations partially offset by higher depreciation and amortization expense as compared to 2016.

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 unaudited interim consolidated statements of operations and unaudited interim 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 March 31
(all dollar amounts in $ millions)	2017				2016
Cash flows from operating activities	$	83.8			$	53.4
Add (deduct):
Changes in non-cash operating items	46.3				46.7
Production based cash contributions from non-controlling interests	9.1				9.5
Interest expense on convertible debentures and acquisition financing fees1	9.3				5.9
Acquisition-related costs	60.4				6.3
Adjusted Funds from Operations	$	208.9			$	121.8

¹  Exclusive of deferred financing fees of $8.3 million.

For the three months ended March 31, 2017, Adjusted Funds from Operations totaled $208.9 million as compared to Adjusted Funds from Operations of $121.8 million, an increase of $87.1 million as compared to the same period in 2016.

Q1 2017 Report	20
Algonquin Power & Utilities Corp. - Management Discussion & Analysis

SUMMARY OF PROPERTY, PLANT, AND EQUIPMENT EXPENDITURES ¹ 

	Three Months Ended March 31
(all dollar amounts in $ millions)	2017				2016
Liberty Power Group:
Maintenance	$	7.8			$	11.4
Investment in Growth Capital Projects1	440.3				16.8
	$	448.1			$	28.2
Liberty Utilities Group:
Rate Base Maintenance	$	56.5			$	28.3
Rate Base Acquisition	2,739.5				345.3
Rate Base Growth	132.7				4.0
	$	2,928.7			$	377.6
Corporate	—				—
Total Capital Expenditures	$	3,376.8			$	405.8

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

2017 First Quarter Property Plant and Equipment Expenditures

During the three months ended March 31, 2017, the Liberty Power Group incurred capital expenditures of $448.1 million as compared to $28.2 million during the same period in 2016. The increase in capital expenditures are primarily due to the acquisition of the remaining outstanding interest in the Deerfield Wind Facility. The balance of capital expenditures were for the construction of the Great Bay Solar project and ongoing maintenance at operating sites.

During the three months ended March 31, 2017, the Liberty Utilities Group incurred capital expenditures of $2,928.7 million as compared to $377.6 million during the same period in 2016. The increase in capital expenditures are primarily due to the acquisition of Empire in January 2017 (U.S. $2,058.2 million), and completion of the Luning Solar Facility located in Mineral County, Nevada, in February 2017 (U.S. $84.9 million). In the prior year, the Liberty Utilities Group completed the acquisition of the Park Water System in January 2016. Other capital expenditures 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.

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 of various project investments and the realized U.S. dollar exchange rate.

Expected 2017 capital investment ranges are as follows:

(all dollar amounts in $ millions)
Liberty Power Group:
Maintenance	$	40.0		-	$	50.0
Investment in Growth Capital Projects	500.0			-	580.0
Total Liberty Power 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 Liberty Power Group, and the Liberty Utilities Group to manage the liquidity and working capital requirements of each division (collectively the “Bank Credit Facilities”).

Bank Credit Facilities

The following table sets out the Bank Credit Facilities available to APUC and its operating groups as at March 31, 2017:

	As at March 31, 2017																As at Dec 31, 2016
(all dollar amounts in $ millions)	Corporate				Liberty Power				Liberty Utilities				Total				Total
Committed facilities	$	65.0			$	439.9			$	532.4			$	1,037.3			$	773.8
Funds drawn on facilities	—				(223.1		)		—				(223.1		)		(242.9		)
Letters of credit issued	(12.0		)		(135.6		)		(43.5		)		(191.1		)		(234.9		)
Liquidity available under the facilities	53.0				81.2				488.9				623.1				296.0
Cash on hand													77.7				110.4
Total Liquidity and Capital Reserves	$	53.0			$	81.2			$	488.9			$	700.8			$	406.4

As at March 31, 2017, the Company's $65.0 million senior unsecured bilateral revolving credit facility (the "Corporate Credit Facility") was undrawn and had $12.0 million of outstanding letters of credit. The facility matures on November 19, 2017 and is subject to customary covenants.

As at March 31, 2017, the Liberty Power Group's committed bank lines consisted of a $350.0 million senior unsecured syndicated revolving credit facility and $89.9 million letter of credit facility (Cdn $50.0 million and U.S. $30.0 million). Subsequent to quarter end, Liberty Power entered into a $150.0 million senior unsecured bilateral revolving credit facility with a Canadian Chartered Bank. The new facility matures on May 19, 2018.

As at March 31, 2017, the Liberty Utilities Group's committed bank lines consisted of a U.S. $200.0 million senior unsecured syndicated revolving credit facility at the holding company and a U.S. $200.0 million revolving credit facility at Empire ("Empire Facility"). The facilities mature on September 30, 2018 and October 20, 2019 respectively. The Empire Facility is used primarily as a backstop to commercial paper issued by Empire (rated P2 Moody's / A2 S&P).

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. On December 30, 2016 the Company drew U.S. $1,336.4 million on the Acquisition Facility in connection with the closing of the Empire Acquisition. The Acquisition Facility was fully repaid in the first quarter from proceeds received from the Final Installment payment and the Liberty Private Placement.

Long Term Debt

On January 17, 2017 the Liberty Power 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 Liberty Power Group entered into a cross currency swap, coterminous with the debentures, to economically convert the Canadian dollar denominated offering into U.S. dollars for an effective yield of 4.86%.

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 The Liberty Utilities Group is 3.6%. The offering closed on March 24, 2017, the proceeds of which were applied to repay the balance of the Acquisition Facility and other existing indebtedness.

As at March 31, 2017, the weighted average tenure of APUC's total long term debt is approximately 11 years with an average interest rate of approximately 4.5%.

Q1 2017 Report	21
Algonquin Power & Utilities Corp. - Management Discussion & Analysis

Convertible Unsecured Subordinated Debentures

In first quarter of 2016, in connection with the acquisition of Empire, the Company completed the sale of $1.15 billion aggregate principal amount of 5.0% convertible debentures ("Debentures"). 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 Installment”) received on February 2, 2017 which was a date set by the Company following the satisfaction of conditions precedent to the closing of the Empire Acquisition. The proceeds received from the First and Final Installment were $383.0 million and $767.1 million, respectively. As the Final Installment 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 Installment date up to and including March 1, 2017.

As at May 10, 2017, a total of 108,075,037 common shares of the company were issued, representing conversion into common shares of 99.6% of the convertible debentures. Any debentures not converted may be redeemed by the Company at a price equal to their principal amount plus any unpaid interest. The convertible debentures mature on March 31, 2026 and currently bear interest at an annual rate of 0%. 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.

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"), the parent company for the Liberty Power Group, 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., the parent company for the Liberty Utilities Group, has a BBB (high) issuer rating from DBRS.

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.

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.

Q1 2017 Report	22
Algonquin Power & Utilities Corp. - Management Discussion & Analysis

Contractual Obligations

Information concerning contractual obligations as of March 31, 2017 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	$	4,704.4			$	435.6			$	717.4			$	755.8			$	2,795.6
Convertible debentures	5.2				—				—				—				5.2
Advances in aid of construction	109.2				3.1				—				—				106.1
Interest on long-term debt obligations	2,067.1				188.7				320.1				264.5				1,293.8
Purchase obligations	477.4				477.4				—				—				—
Environmental obligations	95.8				8.0				19.7				7.6				60.5
Derivative financial instruments:
Cross currency swap	102.2				6.3				11.4				81.9				2.6
Interest rate swap	14.5				—				14.5				—				—
Commodity contracts	4.2				2.1				2.1				—				—
Purchased power	541.6				64.4				102.4				93.6				281.2
Gas delivery, service and supply agreements	438.9				105.3				149.1				74.8				109.7
Service agreements	736.8				46.2				95.2				101.9				493.5
Capital projects	88.2				68.7				19.4				0.1				—
Operating leases	295.0				10.5				19.6				17.9				247.0
Other obligations	184.5				52.9				—				—				131.6
Total Obligations	$	9,865.0			$	1,469.2			$	1,470.9			$	1,398.1			$	5,526.8

1 Exclusive of deferred financing costs, bond premium/discount and 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 March 31, 2017, APUC had 384,672,285 issued and outstanding common shares.

APUC may issue an unlimited number of common shares.  The holders of common shares are entitled to dividends, if and when declared; to one vote for each share at meetings of the holders of common shares; and to receive a pro rata share of any remaining property and assets of APUC upon liquidation, dissolution or winding up of APUC.  All shares are of the same class and with equal rights and privileges and are not subject to future calls or assessments.

In the first quarter of 2016, in connection with the acquisition of Empire, APUC and its direct wholly-owned subsidiary, Liberty Utilities (Canada) Corp., entered into an agreement with a syndicate of underwriters under which the underwriters agreed to buy, on a bought deal basis, $1.15 billion aggregate principal amount of 5.00% convertible unsecured subordinated debentures of APUC.

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 ("The Final Instalment Date"), at which time each debenture was convertible to 94.3396 common shares of APUC and bears an interest rate of 0% thereafter.

The Final Instalment Date was established as February 2, 2017, at which time APUC received the Final Instalment payment 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. As of May 10, 2017, $4.4 million of convertible debentures remain outstanding.

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 March 31, 2017, 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

Q1 2017 Report	23
Algonquin Power & Utilities Corp. - Management Discussion & Analysis

• 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 March 31, 2017, 61,419,484 common shares representing approximately 16% of total common shares outstanding had been registered with the Reinvestment Plan. During the quarter ended March 31, 2017, 823,738 common shares were issued under the Reinvestment Plan, and subsequent to the end of the quarter, on April 14, 2017, an additional 821,936 common shares were issued under the Reinvestment Plan.

Base Shelf Prospectus

On March 17, 2017 APUC filed a base shelf prospectus allowing for the issuance of up to $2 billion of specified securities in both Canada and the US.

SHARE BASED COMPENSATION PLANS

For the three months ended March 31, 2017, APUC recorded $2.3 million in total share-based compensation expense as compared to $1.0 million for the same period in 2016. There is no significant tax benefit associated with the share-based compensation expense. The compensation expense is recorded as part of administrative expenses in the unaudited interim consolidated statement of operations. The portion of share-based compensation costs capitalized as cost of construction is insignificant.

As at March 31, 2017, total unrecognized compensation costs related to non-vested options and share unit awards were $6.1 million and $5.1 million, respectively, and are expected to be recognized over a period of 2.03 and 2.29 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 three months ended March 31, 2017, the Company granted 2,328,343 options to executives of the Company. The options allow for the purchase of common shares at a weighted average price of $12.82, the market price of the underlying common share at the date of grant. In March 2017, executives of the Company exercised 1,469,362 stock options at a weighted average exercise price of $7.81 in exchange for common shares issued from treasury and 165,139 options were settled at their cash value as payment for tax withholdings related to the exercise of the options.

As at March 31, 2017, a total of 6,738,856 options are issued and outstanding under the plan.

Performance Share Units

APUC issues performance share units (“PSUs”) to certain members of management as part of APUC’s long-term incentive program.  During the three months ended March 31, 2017, the Company granted (including dividends and performance adjustments) 398,361 PSUs to executives and employees of the Company. During the year the Company settled 365,437 PSUs, of which 173,499 PSUs were exchanged for common shares issued from treasury and 182,463 PSUs were settled at their cash value as payment for tax withholdings related to the settlement of the PSUs. Additionally, during the quarter a total of 967 PSUs were forfeited.

As at March 31, 2017, a total of 610,945 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 three months ended March 31, 2017, the Company issued 17,510 DSUs (including DSUs in lieu of dividends) to the directors of the Company.

As at March 31, 2017, a total of 242,173 DSUs had been granted under the DSU plan.

Q1 2017 Report	24
Algonquin Power & Utilities Corp. - Management Discussion & Analysis

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 three months ended March 31, 2017, the Company issued 137,612 common shares to employees under the ESPP.

As at March 31, 2017, a total of 633,642 shares had been issued under the ESPP.

RELATED PARTY TRANSACTIONS

Emera Inc.

A member of the Board of APUC is an executive at Emera. During the three months ended March 31, 2017, the Energy Services Business sold electricity to Maine Public Service Company and Bangor Hydro, both of which are subsidiaries of Emera, amounting to U.S. $3.0 million as compared to U.S. $2.6 million during the same period in 2016. During the three months ended March 31, 2017, the Liberty Utilities Group purchased natural gas amounting to U.S. $0.9 million as compared to U.S. $1.9 million during the same period in 2016 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. In 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 transmission upgrade was placed in service in April 2017 with final completion of the contract work expected in June 2017. The total cost of the contract is estimated at $8.8 million. The contract followed a market-based request for proposal process.

There was U.S. $2.6 million included in accruals for the three months ended March 31, 2017, as compared to U.S. $0.3 million during the same period in 2016, related to these transactions.

Equity-method investments

The Company provides administrative services to its equity-method investees and is reimbursed for incurred costs. To that effect, for the three months ended March 31, 2017, the Company charged its equity-method investees $0.4 million as compared to $0.7 million during the same period in 2016.

Trafalgar

In 2016, the Company received U.S. $10.1 million in proceeds from the settlement of the Trafalgar matter, and paid U.S.$2.9 million to an entity partially and indirectly owned by Senior Executives as its proportionate share. The gain to APUC, net of legal and other liabilities, of approximately U.S. $6.6 million was recorded in 2016.

Long Sault Hydro Facility

Effective December 31, 2013, APUC acquired the shares of Algonquin Power Corporation Inc. (“APC”) which was partially owned by Senior Executives.  APC owns the partnership interest in the 18 MW Long Sault Hydro Facility.  A final post-closing adjustment related to the transaction is expected to be settled in 2017.

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

ENTERPRISE RISK MANAGEMENT

An enterprise risk management ("ERM") framework is embedded across the organization that systematically and broadly identifies, assesses, and mitigates the key strategic, operational, financial, and compliance risks that may impact the achievement of our objectives. The risks discussed below are not intended as a complete list of all exposures that APUC is encountering or may encounter. A further assessment of APUC and its subsidiaries’ business risks is also set out in the most recent AIF and the annual MD&A.

Interest Rate Risk

The majority of debt outstanding in APUC and its subsidiaries is subject to a fixed rate of interest and as such is not subject to interest rate risk. Borrowings subject to variable interest rates are as follows:

• The Corporate revolving credit facility is subject to a variable interest rate and had no amounts outstanding as at March 31, 2017. As a result, a 100 basis point change in the variable rate charged would not impact interest expense;

• The Liberty Power Group revolving credit facility is subject to a variable interest rate and had $223.1 million outstanding as at March 31, 2017. A 100 basis point change in the variable rate charged would impact interest expense by $2.2 million annually;

Q1 2017 Report	25
Algonquin Power & Utilities Corp. - Management Discussion & Analysis

• The Liberty Utilities Group revolving credit facility is subject to a variable interest rate and had no amounts outstanding as at March 31, 2017. As a result, a 100 basis point change in the variable rate charged would not impact interest expense;

• The Liberty Utilities Group commercial paper program is subject to a variable interest rate and had $10.0 million (U.S. $7.5 million) outstanding as at March 31, 2017. A 100 basis point change in the variable rate charged would impact interest expense by $0.1 million annually;

• The Corporate term credit facility is subject to a variable interest rate and had $179.7 million (U.S. $135.0 million) outstanding as at March 31, 2017. A 100 basis point change in the variable rate charged would impact interest expense by $1.8 million annually; and

• The Park Water System term credit facility is subject to a variable interest rate and had $29.9 million (U.S. $22.5 million) outstanding as at March 31, 2017. A 100 basis point change in the variable rate charged would impact interest expense by $0.3 million annually.

APUC does not actively manage interest rate risk on its variable interest rate borrowings due to the primarily short term and revolving nature of the amounts drawn.

Litigation Risks and Other Contingencies

APUC and certain of its subsidiaries are involved in various litigations, claims and other legal proceedings that arise from time to time in the ordinary course of business.  Any accruals for contingencies related to these items are recorded in the financial statements at the time it is concluded that a material financial loss is likely and the related liability is estimable.  Anticipated recoveries under existing insurance policies are recorded when reasonably assured of recovery.

Long Sault Global Adjustment Claim

In December 2012, N-R Power and Energy Corp., Algonquin Power (Long Sault) Partnership and N-R Power Partnership (“Long Sault”) commenced proceedings (together with the other similarly affected non-utility generators) against the OEFC relating to the OEFC’s interpretation of certain provisions of a PPA between Long Sault and the OEFC, in relation to the use of the global adjustment as a price escalator. On October 21, 2016, following numerous unsuccessful court proceedings, the OEFC made retroactive payments of $5.1 million and $0.3 million of interest to Long Sault. OEFC also sought leave to appeal to the Supreme Court of Canada (the “SCC”). On January 19, 2017, the SCC denied OEFC’s application for leave to appeal.

Market Price Risk

The Liberty Power Group predominantly enters into long term PPAs for its generation assets and hence is not exposed to market risk for this portion of its portfolio. Where a generating asset is not covered by a power purchase contract, the Liberty Power Group may seek to mitigate market risk exposure by entering into financial or physical power hedges requiring that a specified amount of power be delivered at a specified time in return for a fixed price. There is a risk that the Company is not able to generate the specified amount of power at the specified time resulting in production shortfalls under the hedge that then requires the Company to purchase power in the merchant market. To mitigate the risk of production shortfalls under hedges, the Liberty Power Group generally seeks to structure hedges to cover less than 100% of the anticipated production, thereby reducing the risk of not producing the minimum hedge quantities. Nevertheless, due to unpredictability in the natural resource or due to grid curtailments or mechanical failures, production shortfalls may be such that the Liberty Power Group may still be forced to purchase power in the merchant market at prevailing rates to settle against a hedge.

Hedges currently put in place by the Liberty Power Group along with residual exposures to the market are detailed below:

The July 1, 2012 acquisition of the Sandy Ridge Wind Facility included a financial hedge, which commenced on January 1, 2013, for a 10 year period.  The financial hedge is structured to hedge 72% of the Sandy Ridge Wind Facility’s expected production volume against exposure to PJM Western Hub current spot market rates. The annual unhedged production based on long term projected averages is approximately 44,000 MW-hrs. Therefore, each U.S. $10 per MW-hr change in the market price would result in a change in revenue of approximately U.S. $0.4 million for the year.

The December 10, 2012 acquisition of the Senate Wind Facility included a physical hedge, which commenced on January 1, 2013, for a 15 year period. The physical hedge is structured to hedge 64% of the Senate Wind Facility’s expected production volume against exposure to ERCOT North Zone current spot market rates.  The annual unhedged production based on long term projected averages is approximately 188,000 MW-hrs. Therefore, each U.S. $10 per MW-hr change in the market price would result in a change in revenue of approximately U.S. $2.0 million for the year.

The December 10, 2012 acquisition of the Minonk Wind Facility included a financial hedge, which commenced on January 1, 2013, for a 10 year period. The financial hedge is structured to hedge 73% of the Minonk Wind Facility’s expected production volume against exposure to PJM Northern Illinois Hub current spot market rates. The annual unhedged production based on long term projected averages is approximately 186,000 MW-hrs. Therefore, each U.S. $10 per MW-hr change in market prices would result in a change in revenue of approximately U.S. $2.0 million for the year.

Under each of the above noted hedges, if production is not sufficient to meet the unit quantities under the hedge, the shortfall must be purchased in the open market at market rates. The effect of this risk exposure could be material but cannot be quantified as it is dependent on both the amount of shortfall and the market price of electricity at the time of the shortfall.

In addition to the above noted hedges, from time to time the Liberty Power Group enters into short-term derivative contracts (with terms of one to three months) to further mitigate market price risk exposure due to production variability. As at March 31, 2017, the Liberty Power Group had not entered into any such short-term derivative contracts.

The January 1, 2013 acquisition of the Shady Oaks Wind Facility included a power sales contract, which commenced on June 1, 2012, for a 20 year period. The power sales contract is structured to hedge the preponderance of the Shady Oaks Wind Facility’s production volume against exposure to PJM ComEd Hub current spot market rates.  For the unhedged portion of production based on expected long term average production, each U.S. $10 per MW-hr change in market prices would result in a change in revenue of approximately U.S. $0.5 million for the year.

Regulatory Risk

Profitability of APUC businesses is, in part, dependent on regulatory climates in the jurisdictions in which those businesses operate. In the case of some Liberty Power Group hydroelectric facilities, water rights are generally owned by governments that reserve the right to control water levels, which may affect revenue.

Condemnation Expropriation Proceedings

Mountain Water is currently the subject of a condemnation lawsuit filed by the city of Missoula.  On August 2, 2016, the Supreme Court of Montana upheld the District Court’s decision that the city of Missoula can proceed with condemnation of Mountain Water’s assets.  Upon taking possession of Mountain Water’s assets, the compensation to be paid by the city of Missoula for such taking will be the value of the utility (determined by the valuation commissioners on November 17, 2015 to be U.S. $88.6 million as of May 6, 2014).  Mountain Water is expected to receive certain additional amounts that may include legal fees, interest, post-valuation capital expenditures and property tax reimbursement.

On December 22, 2015, various developers filed a lawsuit in Missoula County District Court against Mountain Water and the city of Missoula.  The lawsuit pertains to Funded By Other ("FBO") contracts between each developer and Mountain Water.   Under these FBO contracts, the developers paid for facilities to provide water service and Mountain Water agreed to refund such amounts over a 40 year period.   As of the date of acquisition of Western Water Holdings, the outstanding balance of these advances, on a non-discounted basis, was U.S. $23.1 million.  On February 21, 2017, the court issued an order imposing equitable liens on the Mountain Water assets that are the subject of the FBO contracts, mandating that the liens be satisfied directly from the condemnation award, if and when paid.

On April 27, 2017, Mountain Water agreed in principle to certain terms with the City of Missoula relating to the condemnation of Mountain Water's assets. The city is expected to take possession of Mountain Water's assets in the second quarter or early in the third quarter of 2017.

Subject to final adjustments, APUC expects that the net effect of the foregoing and terms of the original acquisition of Mountain Water will result in Liberty Utilities receiving an amount of approximately U.S. $103.0 million from the disposition of the utility.  

The Town of Apple Valley has initiated a process with the objective to condemn the assets of Liberty Apple Valley.  A ballot measure initiated by citizens of Apple Valley and supported by the Company passed during the November 2016 election. This measure requires the Town of Apple Valley to put to a public vote any debt over U.S. $10.0 million to be issued related to an enterprise fund activity. On March 9, 2017, the Apple Valley Town Council voted to call a special election on June 6, 2017 to approve a ballot measure to authorize the Town to incur U.S. $150.0 million in bonds for the purpose of funding an attempted taking of the Apple Valley Water System. The entire condemnation process, even if successful, is expected to take several years to resolve.

Cycles and Seasonality

Liberty Power Group

The Liberty Power Group's hydroelectric operations are impacted by seasonal fluctuations and year to year variability of the available hydrology. These assets are primarily “run-of-river” and as such fluctuate with natural water flows. During the winter and summer periods, flows are generally lower while during the spring and fall periods flows are generally higher. The ability of these assets to generate income may be impacted by changes in water availability or other material hydrologic events within a watercourse. Year to year the level of hydrology varies, impacting the amount of power that can be generated in a year.

The Liberty Power Group's wind generation facilities are impacted by seasonal fluctuations and year to year variability of the wind resource. During the spring and fall periods, winds are generally stronger than during the summer periods. The ability of these facilities to generate income may be impacted by naturally occurring changes in wind patterns and wind strength.

The Liberty Power Group's solar generation facilities are impacted by seasonal fluctuations and year to year variability in the solar radiance. For instance, there are more daylight hours in the summer than there are in the winter, resulting in higher

Q1 2017 Report	26
Algonquin Power & Utilities Corp. - Management Discussion & Analysis

production in the summer months. The ability of these facilities to generate income may be impacted by naturally occurring changes in solar radiance.

The Company attempts to mitigate the above noted natural resource fluctuation risks by acquiring or developing generating stations in different geographic locations.

Liberty Utilities Group

The Liberty Utilities Group’s demand for water is affected by weather conditions and temperature. Demand for water during warmer months is generally greater than cooler months due to requirements for irrigation, swimming pools, cooling systems and other outside water use. If there is above normal rainfall or rainfall is more frequent than normal the demand for water may decrease, adversely affecting revenues.

The Liberty Utilities Group’s demand for energy from its electric distribution systems is primarily affected by weather conditions and conservation initiatives. The Liberty Utilities Group provides information and programs to its customers to encourage the conservation of energy. In turn, demand may be reduced which could have short term adverse impacts on revenues.

The Liberty Utilities Group's primary demand for natural gas from its natural gas distribution systems is driven by the seasonal heating requirements of its residential, commercial, and industrial customers. The colder the weather the greater the demand for natural gas to heat homes and businesses. As such, the natural gas distribution systems demand profiles typically peaks in the winter months of January and February and declines in the summer months of July and August. Year to year variability also occurs depending on how cold the weather is in any particular year.

The Company attempts to mitigate the above noted risks by seeking regulatory mechanisms during rate case proceedings. Certain jurisdictions have approved constructs to mitigate demand fluctuations. For example, at the Peach State Gas System in Georgia, a weather normalization adjustment is applied to customer bills during the months of October through May that adjusts commodity rates to stabilize the revenues of the utility for changes in billing units attributable to weather patterns. Not all regulatory jurisdictions in which the Liberty Utilities Group operates have approved mechanisms to mitigate demand fluctuations.

Q1 2017 Report	27
Algonquin Power & Utilities Corp. - Management Discussion & Analysis

QUARTERLY FINANCIAL INFORMATION

The following is a summary of unaudited quarterly financial information for the eight quarters ended March 31, 2017:

(all dollar amounts in $ millions except per share information)	2nd Quarter 2016				3rd Quarter 2016				4th Quarter 2016				1st Quarter 2017
Revenue	$	222.8			$	221.3			$	310.2			$	557.9
Net earnings attributable to shareholders from continuing operations	24.8				17.7				46.3				26.0
Net earnings attributable to shareholders	24.8				17.7				46.3				26.0
Net earnings per share from continuing operations	0.08				0.06				0.16				0.07
Net earnings per share	0.08				0.06				0.16				0.07
Adjusted Net Earnings	30.9				26.6				51.4				88.1
Adjusted Net Earnings per share	0.11				0.09				0.18				0.25
Adjusted EBITDA	99.2				91.4				138.3				254.8
Total assets	5,555.0				6,020.8				8,249.5				10,880.7
Long term debt1	2,199.9				2,380.8				4,272.0				4,773.6
Dividend declared per common share	$	0.14			$	0.14			$	0.14			$	0.15
	2nd Quarter 2015				3rd Quarter 2015				4th Quarter 2015				1st Quarter 2016
Revenue	$	196.2			$	189.6			$	260.3			$	341.7
Net earnings attributable to shareholders from continuing operations	20.6				16.7				38.1				42.0
Net earnings attributable to shareholders	19.9				16.5				38.0				42.0
Net earnings per share from continuing operations	0.07				0.06				0.14				0.15
Net earnings per share	0.07				0.05				0.14				0.15
Adjusted Net Earnings	22.2				17.3				39.7				56.1
Adjusted Net Earnings per share	0.08				0.06				0.15				0.21
Adjusted EBITDA	81.1				70.2				109.6				147.9
Total assets	4,396.5				4,759.0				4,991.7				5,615.5
Long term debt1	1,440.3				1,613.3				1,486.8				2,214.5
Dividend declared per common share	$	0.12			$	0.13			$	0.13			$	0.13

1 Includes current portion of long-term debt, long-term debt and convertible debentures.

The quarterly results are impacted by various factors including seasonal fluctuations and acquisitions of facilities as noted in this MD&A.

Quarterly revenues have fluctuated between $189.6 million and $557.9 million over the prior two year period. A number of factors impact quarterly results including acquisitions, seasonal fluctuations, and winter and summer rates built into the PPAs. In addition, a factor impacting revenues year over year is the fluctuation in the strength of the Canadian dollar relative to the U.S. dollar which can result in significant changes in reported revenue from U.S. operations.

Quarterly net earnings attributable to shareholders have fluctuated between net earnings attributable to shareholders of $16.5 million and net earnings of $46.3 million over the prior two year period. Earnings have been significantly impacted by non-cash factors such as deferred tax recovery and expense, impairment of intangibles, property, plant and equipment and mark-to-market gains and losses on financial instruments.

DISCLOSURE CONTROLS

As of March 31, 2017, APUC carried out an evaluation, under the supervision of and with the participation of APUC’s management, including the Chief Executive Officer (“CEO”) and the Chief Financial Officer (“CFO”), of the effectiveness of the design and operations of APUC’s disclosure controls and procedures (as defined in Rule 13a – 15(e) and Rule 15d – 15(e) under the Securities Exchange Act of 1934, as amended (the “Exchange Act”)). Based on that evaluation, the CEO and the CFO have concluded that as of March 31, 2017, APUC’s disclosure controls and procedures are effective.

Q1 2017 Report	28
Algonquin Power & Utilities Corp. - Management Discussion & Analysis

INTERNAL CONTROLS OVER FINANCIAL REPORTING

Management, including the CEO and the CFO, is responsible for establishing and maintaining internal control over financial reporting. Management, as at the end of the period covered by this interim filing, designed internal controls over financial reporting to provide reasonable, but not absolute, assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with U.S. GAAP. The control framework management used to design the issuer's internal control over financial reporting is that established in Internal Control - Integrated Framework (2013) issued by the Committee of Sponsoring Organizations of the Treadway Commission.

APUC acquired Empire during the three months ended March 31, 2017. The financial information for this acquisition is included in this MD&A and in note 3 to the unaudited interim consolidated financial statements. National Instrument 52-109 and the U.S. Securities and Exchange Commission provide an exemption, whereby companies undergoing acquisitions, can exclude the acquired business in the year of acquisition from the scope of testing and assessment of design and operational effectiveness of controls over financial reporting. Due to the complexity associated with assessing internal controls during integration efforts, the Company plans to utilize the scope exemption as it relates to this acquisition in its management report on internal controls over financial reporting for the year ending December 31, 2017.

For the three months ended March 31, 2017, there has been no change in APUC’s internal control over financial reporting that has materially affected, or is reasonably likely to materially affect, APUC’s internal control over financial reporting. APUC continues to apply its internal control structure over the operations of the acquired business discussed above.

CRITICAL ACCOUNTING ESTIMATES AND POLICIES

APUC prepared its unaudited interim consolidated financial statements in accordance with U.S. GAAP.  The preparation of consolidated financial statements requires management to make estimates and assumptions that affect the reported amounts of assets and liabilities, related amounts of revenues and expenses, and disclosure of contingent assets and liabilities.  Significant areas requiring the use of management estimates relate to the useful lives and recoverability of long-lived assets, intangibles, and goodwill, recoverability of deferred tax assets, rate-regulation, unbilled revenue, pension and post-employment benefits, fair value of derivatives and fair value of assets and liabilities acquired in a business combination.  Actual results may differ from these estimates.

APUC’s significant accounting policies and new accounting standards are discussed in notes 1 and 2 to the unaudited interim consolidated financial statements, respectively.

Q1 2017 Report	29
Algonquin Power & Utilities Corp. - Management Discussion & Analysis