Algonquin Power & Utilities (AQN) 40-F 2015 FY Annual report (Canada)

Exhibit 99.3

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 and twelve months ended December 31, 2015. The Management Discussion & Analysis ("MD&A") should be read in conjunction with APUC’s audited consolidated financial statements for the years ended December 31, 2015 and 2014. 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 March 10, 2016.

Caution concerning forward-looking statements and non-GAAP Measures

Forward-looking statements

Certain statements included herein contain forward-looking information within the meaning of certain securities laws. These statements reflect the views of APUC with respect to future events, based upon assumptions relating to, among others, the performance of APUC’s assets and 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”, “per share cash provided by adjusted funds from operations”, “per share cash provided by operating activities”, "net energy sales", and "net utility sales", are used throughout this MD&A. The terms “adjusted net earnings”, “per share cash provided by operating activities”, “adjusted funds from operations”, “per share cash provided by adjusted funds from operations”, Adjusted EBITDA, "net energy sales" and "net utility sales" are not recognized measures under GAAP. There is no standardized measure of “adjusted net earnings”, Adjusted EBITDA, “adjusted funds from operations”, “per share cash provided by adjusted funds from operations”, “per share cash provided by operating activities”, "net energy sales", and "net utility sales" 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”, “per share cash provided by adjusted funds from operations”, “per share cash provided by operating activities”, "net energy sales" and "net utility sales" can be found throughout this MD&A. Per share cash provided by operating activities is not a substitute measure of performance for earnings per share. Amounts represented by per share cash provided by operating activities do not represent amounts available for distribution to shareholders and should be considered in light of various charges and claims against APUC.

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 and are viewed as not directly related to a company’s operating performance. Net earnings of APUC can be impacted positively or negatively by gains and losses on derivative financial instruments, including foreign exchange forward contracts, interest rate swaps and energy forward purchase contracts as well as to movements in foreign exchange rates on foreign currency denominated debt and working capital balances. Adjusted weighted average shares outstanding represents weighted average shares outstanding adjusted to remove the dilution effect related to shares issued in advance of funding requirements. 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.

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 and are viewed as not directly related to a company’s operating performance. Cash flows from operating activities of APUC can be impacted positively or negatively by changes in working capital balances, acquisition expenses, litigation expenses cash provided or used in discontinued operations. Adjusted weighted average shares outstanding represents weighted average shares outstanding adjusted to remove the dilution effect related to shares issued in advance of funding requirements. 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 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.

Net energy sales

Net energy sales are a non-GAAP measure used by investors to identify revenue after commodity costs used to generate revenue where revenue generally is increased or decreased in response to increases or decreases in the cost of the commodity 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 revenue that is charged. 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 commodities 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 the utility customer. 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. Capitalized terms used herein and not otherwise defined will have the meanings assigned to them in the Company's 2014 Annual Information Form.

2015 Annual Report	2
Algonquin Power & Utilities Corp. - Management's Discussion & Analysis

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 a quarterly dividend augmented by share price appreciation arising from dividend growth supported by increasing per share cash flows and earnings.

APUC’s current quarterly dividend to shareholders is U.S. $0.09625 per share or U.S. $0.3850 per share on an annual basis. Based on exchange rates as at March 10, 2016, the quarterly dividend is equivalent to CAD $0.12872 per share or CAD $0.51486 per 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 and mitigate the impact of fluctuations in foreign exchange rates. 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 three business units consisting of Generation, Transmission and Distribution. The Generation Business Group ("Generation Group") owns and operates a diversified portfolio of non-regulated renewable and thermal electric generation utility assets; the Transmission Business Group ("Transmission Group") is responsible for evaluating and capitalizing upon natural gas pipeline and electric transmission asset opportunities in North America; and the Distribution Business Group ("Distribution Group") owns and operates a portfolio of North American electric, natural gas and water distribution and wastewater collection utility systems.

Generation Business Group

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

The Generation Group owns or has interests in hydroelectric, wind, solar, and thermal facilities with a combined generating capacity of approximately 120 MW, 700 MW, 30MW, and 335 MW respectively. Approximately 83% of the electrical output from the hydroelectric, wind and solar generating facilities is sold pursuant to long term contractual arrangements which have a weighted average remaining contract life of 14 years.

The Generation Group also has a portfolio of development projects that between 2016 and 2018 will add approximately 711 MW of generation capacity from wind and solar powered generating facilities with an average contract life of 21 years.

Distribution Business Group

The Distribution Group operates diversified rate regulated electricity, natural gas, water distribution and wastewater collection utility services to approximately 489,000 connections, excluding the Park Water System. The Distribution Group provides safe, high quality and reliable services to its ratepayers through its nationwide portfolio of utility systems and delivers stable and predictable earnings to APUC. In addition to encouraging and supporting organic growth within its service territories, the Distribution Group delivers continued growth in earnings through accretive acquisition of additional utility systems.

The Distribution Group's regulated electrical distribution utility systems and related generation assets are located in the States of California and New Hampshire; and together serve approximately 93,000 electric connections.

The Distribution Group's regulated natural gas distribution utility systems are located in the States of Georgia, Illinois, Iowa, Massachusetts, Missouri and New Hampshire; and together serve approximately 292,000 natural gas connections.

The Distribution Group's regulated water distribution and wastewater collection utility systems are located in the States of Arizona, Arkansas, Illinois, Missouri, and Texas; and together serve approximately 104,000 connections. On January 8, 2016, the Distribution Group completed its acquisition of the Park Water System which is comprised of two water and wastewater facilities in California and one facility in Montana. This acquisition adds another 74,000 connections to the Distribution Group's present water and wastewater footprint.

Transmission Business Group

In 2014, APUC created a Transmission Group that is responsible for identifying, evaluating and capitalizing upon natural gas pipeline and electric transmission investment opportunities in North America. The Company believes that the creation of the Transmission Group complements the growth of both the Generation and Distribution Groups.

2015 Annual Report	3
Algonquin Power & Utilities Corp. - Management's Discussion & Analysis

Major Highlights

Corporate Highlights

Declaration of Canadian equivalent first quarter dividend of Cdn $0.1287 (U.S. $0.0963) per Common Share

On March 10, 2016, APUC announced that the Board of Directors of APUC declared the first quarter 2016 dividends of U.S. $0.0963 per common share. Based on the Bank of Canada noon exchange rate on the declaration date, the Canadian dollar equivalent for the first quarter 2016 dividends is set at Cdn $0.1287 per common share.

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

	Q2 2015	Q3 2015	Q4 2015	Q1 2016		Total
U.S. dollar Dividend	$0.0963	$0.0963	$0.0963	$	0.0963	$0.3850
Canadian dollar equivalent	$0.1201	$0.1289	$0.1267	$	0.1287	$0.5044

Pending Acquisition of The Empire District Electric Company

On February 9, 2016 APUC announced that through a wholly owned subsidiary it has entered into an agreement and plan of merger pursuant to which it will acquire The Empire District Electric Company (“Empire”) (NYSE:EDE) and its subsidiaries (the “Acquisition”).

Under the terms of the all-cash transaction, which has been unanimously approved by the Board of Directors of each company, Empire’s shareholders will receive U.S. $34.00 per common share (the “Purchase Price”), representing an aggregate purchase price of approximately $3.4 billion (U.S. $2.4 billion), including the assumption of approximately $1.3 billion (U.S. $0.9 billion) of debt as of September 30, 2015. The Purchase Price represents a 21% premium to the closing price on February 8, 2016 and a 50% premium to Empire’s unaffected share price on December 10, 2015.

Closing of the Acquisition is subject to customary closing conditions, including the approval of Empire’s common shareholders, and the receipt of certain state and federal regulatory and government approvals, including approval of the relevant commissions of the states of Arkansas, Kansas, Missouri and Oklahoma (collectively, the State Commissions), the Federal Communications Commission (the "FCC"), the Committee on Foreign Investment in the United States and the Federal Energy Regulatory Commission (the "FERC"), and the expiration or termination of the waiting period under the Hart-Scott-Rodino Act. The Transaction is expected to close in Q1 2017.

Empire is a Joplin, Missouri based regulated electric, gas (through its wholly-owned subsidiary The Empire District Gas Company), and water utility, collectively serving approximately 218,000 customers in Missouri, Kansas, Oklahoma, and Arkansas.

APUC expects the Acquisition will be accretive to earnings per common share in the first full year following closing and approximately 7% - 9% accretive to APUC's net earnings per common share over a three-year period following closing, excluding one-time acquisition-related expenses, and assuming a stable currency exchange environment. APUC also expects that the Acquisition will be approximately 12% - 14% accretive to Adjusted Funds from Operations per Common Share over a three-year period following closing, excluding one-time Acquisition-Related Expenses, and assuming a stable currency exchange environment. The Acquisition is expected to remain accretive to APUC's net earnings and cash from operating activities notwithstanding a scenario in which the Canadian dollar strengthens.

The Acquisition adds a large profitable regulated distribution and generation business, increasing APUC's scale, diversity of customers and geographies of service. APUC believes the increased contribution from regulated operations will further enhance the stability and predictability of Adjusted EBITDA, net earnings and quality of cash flows.

$1 Billion Bought Deal Offering of Convertible Unsecured Subordinated Debentures Represented by Instalment Receipts

On February 9, 2016, in connection with the acquisition of Empire, APUC and its direct wholly-owned subsidiary, Liberty Utilities (Canada) Corp., entered into an agreement with a syndicate of underwriters under which the underwriters agreed to buy, on a bought deal basis, $1.0 billion aggregate principal amount of 5.00% convertible unsecured subordinated debentures ("Debentures") of APUC (the "Debenture Offering"). On March 9, 2016, the Underwriters exercised their option to purchase an additional $150 million of Debentures bringing the total amount of Debentures under the Debenture Offering to $1.15 billion.

All Debentures were sold on an instalment basis at a price of $1,000 dollars per Debenture, of which $333 dollars was paid on the closing of the Offering (the "First Instalment") and the remaining C$667 dollars (the "Final Instalment") is payable on a date (the "Final Instalment Date") to be fixed by APUC following satisfaction of all conditions precedent to the closing of APUC's acquisition of Empire.

See also Convertible Unsecured Subordinated Debentures in Liquidity and Capital Reserves.

2015 Annual Report	4
Algonquin Power & Utilities Corp. - Management's Discussion & Analysis

U.S. $235 Million Term Credit Facility

Subsequent to the year end, Algonquin entered into a U.S. $235.0 million term credit facility with two U.S. banks. The proceeds of the term credit facility provide the company with additional liquidity for general corporate purposes and acquisitions. The facility matures on July 5, 2017.

$150 Million Bought Deal Offering Common Shares

On December 2, 2015 APUC issued on a bought deal basis (the "December Offering") 14,355,000 Common Shares at a price of $10.45 per share for gross proceeds of approximately $150 million.

Net proceeds of the December Offering are being used to partially fund APUC's capital growth program, to reduce short-term debt and for general corporate purposes.

Generation Group Highlights

Deerfield Wind Project Joint Venture

On October 19, 2015, the Generation Group announced it has agreed to jointly develop a 150 MW construction stage wind project (the "Deerfield Wind Project") in the United States with Renewable Energy Systems Americas Inc.

The Deerfield Wind Project is located in central Michigan and is being constructed on approximately 20,000 acres of land leased from a supportive wind power land owner group. The project will utilize 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 a local electric distribution utility serving approximately 260,000 customers in Michigan.

The total project cost is expected to be approximately U.S. $303.0 million. The project is expected to achieve commercial operation at the end of 2016, with its first full year of operation being 2017.

Great Bay Solar Project

On December 1, 2015, the Generation Group announced the development of a new 75 MW contracted solar generation facility, located in Somerset County Maryland ("Great Bay Solar Project").  The U.S. $180.0 million facility will be constructed over the next twelve months, with commercial operations expected in late 2016 or early 2017. The facility is contracted under a 10 year PPA and expected to generate 152 GW-hrs annually. The facility will also generate SRECs which will be sold into the Maryland market.

Letter of Credit Facility

On October 30, 2015, the Generation Group entered into a new extendible one year letter of credit facility (the "Generation LC Facility") agreement. The new facility expands the group's available liquidity by providing for issuances of letters of credit based on two separate tranches of Cdn $50.0 million and U.S. $30.0 million. Upon closing, certain letters of credit issued on the existing Generation Credit Facility were transferred to the new facility.

Completion of Morse Wind Facility

On April 22, 2015 the Generation Group completed construction a 23 MW wind generating facility, located near Morse, Saskatchewan ("Morse Wind Project"). The facility is the Generation Group's eighth wind generating facility and consists of 10 2.3 MW direct drive wind turbine generators installed over 1,120 acres of land. The facility is expected to generate 104 GW-hrs of energy per year which is being sold under a 20 year PPA with a large investment grade electric utility.

Completion of Bakersfield I Solar Facility

On April 14, 2015 the Generation Group achieved commercial operation in accordance with the provisions within the PPA on the 20 MW solar generating facility located in Kern County, California (the "Bakersfield I Solar Facility"). The facility is the Generation Group's second solar generating facility and is comprised of approximately 85,000 solar panels located on 165 acres of land. The project is expected to generate 53.3 GW-hrs of energy per year which is being sold under a 20 year PPA with a large investment grade electric utility.

Consistent with the commitment to expand its solar generation portfolio, the Generation Group is currently pursuing the construction of the 10 MW Bakersfield II Solar Project immediately adjacent to the Bakersfield I Solar Generation Project, which is estimated to be operational in the first half of 2016.

Distribution Group Highlights

Acquisition of the Park Water System

On January 8, 2016, the Distribution Group closed a previously announced agreement with Western Water Holdings, a wholly-owned investment of Carlyle Infrastructure, to acquire the regulated water distribution utility Park Water Company, now known as Liberty Utilities (Park Water) Corp. (the "Park Water System"). The acquisition of the Park Water System

2015 Annual Report	5
Algonquin Power & Utilities Corp. - Management's Discussion & Analysis

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

Total consideration for the utility purchase was U.S. $341.8 million, which includes the assumption of approximately U.S. $91.8 million of existing long-term utility debt. This acquisition maintains APUC's strategic business mix and further enhances its investment grade consolidated capital structure.

The water utility located in western Montana is currently the subject of a condemnation proceeding by the city of Missoula. It is not known when the condemnation proceeding will conclude or whether the city of Missoula will ultimately take possession of Mountain Water (see Enterprise Risk Management, Regulatory Risk).

Successful Rate Case Outcomes

A core strategy of the Distribution Group is to ensure an appropriate return on the rate base at its various utility systems. During 2015, the Distribution Group successfully completed several rate cases representing a cumulative annual revenue increase of approximately U.S. $18.1 million. Subsequent to the year end, the Distribution Group concluded the New England Natural Gas and Peach State Natural Gas System rate cases which resulted in U.S. $11.0 million in increased rates. The full annualized impact of these rate cases will be realized in 2016.

U.S. Debt Private Placement

On April 30, 2015, the Distribution Group entered into a Note Purchase Agreement for the issuance of U.S. $160.0 million of senior unsecured 30 year notes bearing a coupon of 4.13% via a private placement in the U.S. The proceeds of the financing was used to partially finance the acquisition of the Park Water System and for general corporate purposes. The notes were issued in two tranches: U.S. $90.0 million was issued immediately on closing and U.S. $70.0 million were issued on July 15, 2015. The notes have been assigned a rating of BBB High by DBRS.

The financing is the fourth series of notes issued pursuant to the company's master indenture.

Acquisition of New Hampshire Gas

On January 2, 2015, the Distribution Group completed the acquisition of New Hampshire Gas, a regulated propane gas distribution utility located in Keene, New Hampshire. The New Hampshire Gas System services approximately 1,200 propane gas distribution customers. Total purchase price for the New Hampshire Gas System was approximately U.S. $3.0 million, subject to certain closing adjustments.

Transmission Group Highlights

Northeast Supply Pipeline

In December 2015, the Transmission Group reached an agreement for acquiring an additional equity investment right in the Supply Link segment to the Northeast Expansion Pipeline, referred to as Northeast Supply Pipeline (“NSP Project”) a joint venture with subsidiaries of Kinder Morgan. The project is a 30 inch greenfield pipeline from northeastern Pennsylvania to Wright, New York traversing 132 miles and having a design capacity of up to 1,200,000 dth/day. The Transmission Group has secured a 4% initial participation right, along with an option to increase its participation to 10%.

The Northeast Expansion Pipeline ("NEP Project") and the NSP Project developer, Tennessee Gas Pipeline, filed a combined FERC application for a Certificate of Public Convenience and Necessity along with a complete Environmental Review in November 2015. A November 2016 FERC order has been requested and a November 2018 project in service date is planned.

2015 Annual Report	6
Algonquin Power & Utilities Corp. - Management's Discussion & Analysis

2015 Fourth Quarter Results From Operations

Key Selected Fourth Quarter Financial Information	Three months ended December 31
(all dollar amounts in $ millions except per share information)	2015		2014
Revenue	$	260.3	$	259.3
Adjusted EBITDA 1	109.6		84.3
Cash provided by operating activities	94.3		96.5
Adjusted funds from operations1	77.2		65.9
Net earnings attributable to Shareholders from continuing operations	38.1		33.1
Net earnings attributable to Shareholders	38.0		31.6
Adjusted net earnings1	39.7		35.2
Dividends declared to Common Shareholders	34.0		25.4
Weighted Average number of common shares outstanding	258,048,584		230,664,583
Per share
Basic net earnings/(loss) from continuing operations	$	0.14	$	0.13
Basic net earnings/(loss)	$	0.14	$	0.13
Adjusted net earnings1, 2,	$	0.15	$	0.14
Diluted net earnings/(loss)	$	0.14	$	0.12
Cash provided by operating activities 1,2	$	0.38	$	0.42
Adjusted funds from operations1,2	$	0.30	$	0.27
Dividends declared to Common Shareholders	$	0.13	$	0.10

1	Non-GAAP Financial Measures
2	APUC uses per share adjusted net earnings, cash provided by operating activities and adjusted funds from operations to enhance assessment and understanding of the performance of APUC.

For the three months ended December 31, 2015, APUC experienced an average U.S. exchange rate of approximately $1.335 as compared to $1.136 in the same period in 2014. As such, any quarter over quarter variance in revenue or expenses, in local currency, at any of APUC’s U.S. entities are affected by a change in the average exchange rate, upon conversion to APUC’s reporting currency.

For the three months ended December 31, 2015, APUC reported total revenue of $260.3 million as compared to $259.3 million during the same period in 2014, an increase of $1.0 million. The major factors resulting in the increase in APUC revenue in the three months ended December 31, 2015 as compared to the corresponding period in 2014 are set out as follows:

2015 Annual Report	7
Algonquin Power & Utilities Corp. - Management's Discussion & Analysis

(all dollar amounts in $ millions)	Three months ended December 31, 2015
Comparative Prior Period Revenue	$	259.3
Existing Facilities: Generation
Hydro Canada: The hydro facilities realized lower production rates at the Quebec and Maritime region.	(2.9		)
Wind Canada: The St Leon Wind Facility experienced decreased wind resources.	(0.8		)
Wind US: Increased wind resources at the Minonk and Shady Oaks Wind Facilities coupled with an increase in market pricing for the sale of REC's. These gains were partially offset by lower wind resources at the Senate and Sandy Ridge Wind Facilities.	4.6
Solar Canada: The Cornwall Solar Facility Experienced increased solar resource.	0.4
Thermal: The thermal facilities experienced a lower cost of gas (which is a direct pass-through to customers).	(1.6		)
Other	(0.2		)
	(0.5		)
New Facilities: Generation
Wind Canada: Increase due to the St Damase and Morse Wind Facilities achieving commercial operations in Q4 2014 and Q2 2015.	4.2
Solar US: Bakersfield I Solar Facility which achieved commercial operation within the provisions of the PPA in Q2 2015.	0.4
	4.6
Foreign Exchange
Increased Generation Group operating profit as a result of a stronger U.S. dollar.	7.3
Existing Facilities: Distribution
Electric Distribution Systems: Decrease in revenue due to decrease in GW-hrs used by commercial customers, partially offset by an increase in revenue at the Calpeco Electric System.	(7.0		)
Natural Gas Distribution Systems: Decrease in Natural Gas Distribution Systems revenues due to lower commodity cost (which are a direct pass-through to customers) and decreased customer demand.	(27.5		)
Water Distribution & Wastewater Treatment Systems: Revenue excluding rate case impact was in line with prior year.	0.2
Other Income: Decreased revenues from contracted services.	(2.9		)
	(37.2		)
New Facilities: Distribution
Natural Gas Distribution Systems: Increase due to New Hampshire Gas which was acquired in Q1 2015.	0.7
Water Distribution & Wastewater Treatment Systems: Decreased demand at the Whitehall Water System.	(0.2		)
	0.5
Rate Cases
Natural Gas Distribution Systems: Successful implementation of new rates at the EnergyNorth and the Missouri Natural Gas System.	3.3
Water Distribution & Wastewater Treatment Systems: Successful implementation of new rates at the LPSCo Water System.	0.2
	3.5
Foreign Exchange
Increased Distribution Group operating profit as a result of a stronger U.S. dollar.	22.8
Current Period Revenue	$	260.3

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

2015 Annual Report	8
Algonquin Power & Utilities Corp. - Management's Discussion & Analysis

Adjusted EBITDA in the three months ended December 31, 2015 totalled $109.6 million as compared to $84.3 million during the same period in 2014, an increase of $25.3 million or 30.0%. The increase in Adjusted EBITDA was primarily due to the St. Damase Wind, Morse Wind, and Bakersfield I Solar Facilities achieving commercial operations, the impact of rate case settlements, increased wind resources, and a stronger U.S. dollar. 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).

For the three months ended December 31, 2015, net earnings attributable to Shareholders from continued operations totalled $38.1 million as compared to $33.1 million during the same period in 2014, an increase of $5.0 million or 15.1%. The increase was due to $22.9 million in increased earnings from operating facilities, $1.2 million in increased interest and dividend income, $2.1 million in decreased gains, $1.1 million in decreased acquisition costs, $2.0 million in increased gains from derivative instruments, and $3.6 million in increased loss attributable to non-controlling interests, as compared to the same period in 2014. These items were partially offset by $12.9 million in increased depreciation and amortization expenses, $2.7 million in increased administration charges, $3.3 million in increased interest expense, $1.0 million increased write-downs on long-lived assets and loss on disposal, and $8.1 million in increased income tax expense (tax explanations are discussed in APUC: Corporate and Other Expenses).

For the three months ended December 31, 2015, net earnings (including discontinued operations) attributable to Shareholders totalled $38.0 million as compared to net earnings attributable to Shareholders of $31.6 million during the same period in 2014, an increase of $6.4 million or 20.3%. Net earnings per share totalled $0.14 for the three months ended December 31, 2015, as compared to net earnings per share of $0.13 during the same period in 2014.

During the three months ended December 31, 2015, cash provided by operating activities totalled $94.3 million or $0.38 per share as compared to cash provided by operating activities of $96.5 million, or $0.42 per share during the same period in 2014. During the three months ended December 31, 2015, adjusted funds from operations totalled $77.2 million or $0.30 per share as compared to adjusted funds from operations of $65.9 million, or $0.27 per share during the same period in 2014. The change in adjusted funds from operations in the three months ended December 31, 2015, is primarily due to increased earnings from operations, as compared to the same period in 2014.

Cash per share provided by operating activities and per share adjusted funds from operations are non-GAAP measures. Per share cash provided by operating activities and per share adjusted funds from operations are not substitute measures of performance for earnings per share. Amounts represented by per share cash provided by operating activities and per share adjusted funds from operations do not represent amounts available for distribution to shareholders and should be considered in light of various charges and claims against APUC.

2015 Annual Report	9
Algonquin Power & Utilities Corp. - Management's Discussion & Analysis

2015 Annual Results From Operations

As outlined, APUC has continued to advance growth initiatives throughout 2015 that had a positive contribution to the annual results.

Key Selected Annual Financial Information	Twelve months ended December 31
(all dollar amounts in $ millions except per share information)	2015		2014		2013
Revenue	$	1,027.9	$	941.6	$	675.3
Adjusted EBITDA 1	375.4		290.5		228.1
Cash provided by operating activities	261.9		192.7		98.9
Adjusted funds from operations1	287.4		206.5		154.9
Net earnings attributable to Shareholders from continuing operations	118.5		77.8		62.3
Net earnings attributable to Shareholders	117.5		75.7		20.3
Adjusted net earnings 1	121.5		88.2		59.5
Dividends declared to Common Shareholders	124.6		82.9		68.3
Weighted Average number of common shares outstanding	253,172,088		213,953,870		204,350,689
Per share
Basic net earnings from continuing operations	$	0.43	$	0.32	$	0.28
Basic net earnings	$	0.42	$	0.31	$	0.07
Adjusted net earnings 1, 2	$	0.46	$	0.37	$	0.26
Diluted net earnings	$	0.42	$	0.31	$	0.07
Cash provided by operating activities 1, 2	$	1.09	$	0.90	$	0.48
Adjusted funds from operations1, 2	$	1.15	$	0.92	$	0.73
Dividends declared to Common Shareholders	$	0.49	$	0.37	$	0.33
Total assets	4,991.7		4,102.8		3,469.3
Long term debt 3	1,486.8		1,271.7		1,248.3

1	Non-GAAP Financial Measures
2	APUC uses per share adjusted net earnings, cash provided by operating activities and adjusted funds from operations to enhance assessment and understanding of the performance of APUC.
3	Includes long-term debt and current portion of long-term debt

For the year ended December 31, 2015, APUC experienced an average U.S. exchange rate of approximately $1.2786 as compared to $1.1049 in the same period in 2014. As such, any year over year variance in revenue or expenses, in local currency, at any of APUC’s U.S. entities are affected by a change in the average exchange rate, upon conversion to APUC’s Canadian dollar reporting currency.

For the year ended December 31, 2015, APUC reported total revenue of $1,027.9 million as compared to $941.6 million during the same period in 2014, an increase of $86.3 million or 9.2%. The major factors resulting in the increase in APUC revenue for the year ended December 31, 2015 as compared to the corresponding period in 2014 are set out as follows:

2015 Annual Report	10
Algonquin Power & Utilities Corp. - Management's Discussion & Analysis

(all dollar amounts in $ millions)	Twelve months ended December 31, 2015
Comparative Prior Year Revenue	$	941.6
Existing Facilities: Generation
Hydro Canada: The hydro facilities realized lower production rates at the Quebec and Maritime Region.	(11.1		)
Wind Canada: The St Leon Wind Facility experienced decreased wind resources.	(1.7		)
Wind US: Increased wind resources at the Minonk and Shady Oaks Wind Facilities coupled with an increase in market pricing for the sale of REC's.	9.2
Solar Canada: The Cornwall Solar Facility experienced increased solar resource.	1.3
Thermal: The thermal facilities experienced a lower cost of gas (which is a direct pass-through to customers).	(8.4		)
Other	(0.3		)
	(11.0		)
New Facilities: Generation
Wind Canada: Increase due to the St Damase and Morse Wind Facilities achieving commercial operations in Q4 2014 and Q2 2015, respectively.	13.4
Solar US: Bakersfield I Solar Facility which achieved commercial operation within the provisions of the PPA in Q2 2015.	2.8
	16.2
Foreign Exchange
Increased Generation Group operating profit as a result of a stronger U.S. dollar.	20.8
Existing Facilities: Distribution
Electric Distribution Systems: Decrease in revenue due to decrease in GW-hrs used by commercial customers, partially offset by an increase in revenue at the Calpeco Electric System.	(7.1		)
Natural Gas Distribution Systems: Decrease in Natural Gas Distribution Systems revenues due to lower commodity cost) which are a direct pass-through to customers) and decreased customer demand.	(58.7		)
Other Income: Increase in revenue from contracted services.	8.2
Other	(1.5		)
	(59.1		)
New Facilities: Distribution
Natural Gas Distribution Systems: Increase due to New Hampshire Gas which was acquired in Q1 2015.	3.3
Water Distribution & Wastewater Treatment Systems: Increase due to White Hall Water & Waste System which was acquired in Q2 2014.	1.3
	4.6
Rate Cases
Electric Distribution Systems: In 2014 the Granite State Electric System retroactively recognized rates pertaining to its 2014 rate case settlement. A similar adjustment was not made in 2015.	(2.4		)
Natural Gas Distribution Systems: Successful implementation of new rates at the EnergyNorth, Illinois, Georgia and the Missouri Natural Gas Systems.	19.9
Water Distribution & Wastewater Treatment Systems: Successful implementation of new rates at the LPSCo Water System.	1.3
	18.8
Foreign Exchange
Increased Distribution Group operating profit as a result of a stronger U.S. dollar.	96.0
Current Year Revenue	$	1,027.9

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

2015 Annual Report	11
Algonquin Power & Utilities Corp. - Management's Discussion & Analysis

Adjusted EBITDA in the year ended December 31, 2015 totalled $375.4 million as compared to $290.5 million during the same period in 2014, an increase of $84.9 million or 29.2%.

For the year ended December 31, 2015, net earnings from continuing operations attributable to Shareholders totalled $118.5 million as compared to $77.8 million during the same period in 2014, an increase of $40.7 million. The increase was due to $85.7 million in increased earnings from operating facilities, $1.5 million in increased foreign exchange gains, $5.1 million due to increased other gains, $1.3 million increased dividend, equity and other income, $0.7 million decreased acquisition related costs, $5.1 million decrease in write-down of long lived assets, $3.6 million increase in gains on derivative financial instruments and $9.8 million increased loss attributable to non-controlling interest as compared to the same period in 2014. These items were partially offset by $35.8 million in increased depreciation and amortization expenses, $6.0 million in increased administration charges, $3.6 million in increased interest expense and $26.9 million in increased income tax expense (tax explanations are discussed in APUC: Corporate and Other Expenses), as compared to the same period in 2014.

For the year ended December 31, 2015, net earnings (including discontinued operations) attributable to Shareholders totalled $117.5 million as compared to $75.7 million during the same period in 2014, an increase of $41.8 million. Net earnings per share totalled $0.42 for the year ended December 31, 2015, as compared to $0.31 during the same period in 2014.

During the year ended December 31, 2015, cash provided by operating activities totalled $261.9 million or $1.09 per share as compared to cash provided by operating activities of $192.7 million, or $0.90 per share during the same period in 2014. During the year ended December 31, 2015, adjusted funds from operations, a non-GAAP measure, totalled $287.4 million or $1.15 per share as compared to adjusted funds from operations of $206.5 million, or $0.92 per share during the same period in 2014, an increase of $80.9 million.

Cash per share provided by operating activities and per share adjusted funds from operations are non-GAAP measures. Per share cash provided by operating activities and per share adjusted funds from operations are not substitute measures of performance for earnings per share. Amounts represented by per share cash provided by operating activities and per share adjusted funds from operations do not represent amounts available for distribution to shareholders and should be considered in light of various charges and claims against APUC.

2015 Annual Report	12
Algonquin Power & Utilities Corp. - Management's Discussion & Analysis

2015 Adjusted EBITDA Summary

Adjusted EBITDA in the year ended December 31, 2015 totalled $375.4 million as compared to $290.5 million during the same period in 2014, an increase of $84.9 million or 29.2%. Adjusted EBITDA (see non-GAAP measures) in the three months ended December 31, 2015 totalled $109.6 million as compared to $84.3 million during the same period in 2014, an increase of $25.3 million or 30.0%. The breakdown of Adjusted EBITDA (see Non-GAAP Performance Measures) by the company's main operating segments and a summary of changes is shown below.

Adjusted EBITDA by segment	Three months ended  December 31						Twelve months ended December 31, 2015
(all dollar amounts in $ millions)	2015			2014			2015			2014
Generation Business Group Operating Profit	$	62.0		$	47.9		$	188.9		$	156.0
Distribution Business Group Operating Profit	59.3			46.6			224.4			166.4
Administration Expenses	(13.2		)	(10.5		)	(40.7		)	(34.7		)
Other Income & Expenses	1.5			0.3			2.8			2.8
Total Algonquin Power & Utilities Adjusted EBITDA	$	109.6		$	84.3		$	375.4		$	290.5
Change in Adjusted EBITDA ($)	$	25.3					$	84.9
Change in Adjusted EBITDA (%)	30.0		%				29.2		%

Change in Adjusted EBITDA Breakdown	Twelve months ended December 31, 2015
(all dollar amounts in $ millions)	Generation			Distribution		Corporate			Total
Prior period Balances	$	156.0		$	166.4	$	(31.9	)	$	290.5
Existing Facilities	(1.9		)	7.0		—			5.1
New Facilities	17.2			0.7		—			17.9
Rate Cases	—			18.8		—			18.8
Foreign Exchange Impact	17.6			31.5		—			49.1
Administration Expenses	—			—		(6.0		)	(6.0		)
Total change during the period	$	32.9		$	58.0	$	(6.0	)	$	84.9
Current Period Balances	$	188.9		$	224.4	$	(37.9	)	$	375.4

Change in Adjusted EBITDA Breakdown	Three months ended  December 31
(all dollar amounts in $ millions)	Generation		Distribution		Corporate			Total
Prior period Balances	$	47.9	$	46.6	$	(10.2	)	84.3
Existing Facilities	1.8		0.2		1.2			3.2
New Facilities	4.9		—		—			4.9
Rate Cases	—		3.5		—			3.5
Foreign Exchange Impact	7.4		9.0		—			16.4
Administration Expenses	—		—		(2.7		)	(2.7		)
Total change during the period	$	14.1	$	12.7	$	(1.5	)	$	25.3
Current Period Balances	$	62.0	$	59.3	$	(11.7	)	$	109.6

2015 Annual Report	13
Algonquin Power & Utilities Corp. - Management's Discussion & Analysis

GENERATION BUSINESS GROUP

The Company’s management’s reporting structure is aligned under three business units: Generation, Transmission and Distribution Business Groups. During the fourth quarter, Management determined that each business unit represents a reporting segment. The comparative information for 2014 has been reclassified to conform with the composition of the reporting segments presented in the current year. At present the Transmission Business group is not material and is therefore grouped with Corporate.

2015 Electricity Generation Performance

	Long Term Average Resource	Three months ended  December 31		Long Term Average Resource	Twelve months ended December 31, 2015
		2015	2014		2015	2014
Performance (GW-hrs sold)
Hydro Facilities:
Maritime Region	45.8	40.4	47.2	177.8	141.8	140.3
Quebec Region1	72.6	72.8	72.3	273.9	260.9	259.4
Ontario Region	31.9	34.3	38.7	133.7	140.7	144.4
Western Region	12.6	13.6	13.4	65.0	56.2	74.1
	162.9	161.1	171.6	650.4	599.6	618.2
Wind Facilities:
St. Damase2	22.7	20.7	4.7	76.9	73.4	4.7
St. Leon	121.4	106.1	119.9	430.2	408.7	441.4
Red Lily3	24.1	20.7	23.8	88.5	78.8	87.7
Morse	30.5	24.0	—	73.9	61.3	—
Sandy Ridge	43.6	43.7	46.7	158.3	150.0	149.0
Minonk	189.7	214.6	195.4	673.7	639.3	648.5
Senate	140.0	134.7	139.0	520.4	467.6	537.6
Shady Oaks	100.5	114.5	92.2	355.6	342.6	339.9
	672.5	679.0	621.7	2,377.5	2,221.7	2,208.8
Solar Facilities:
Cornwall	2.1	2.3	1.8	14.6	15.2	12.8
Bakersfield	8.9	6.4	—	43.7	36.1	—
	11.0	8.7	1.8	58.3	51.3	12.8
Thermal Facilities:
Windsor Locks	N/A4	25.5	26.3	N/A4	131.9	112.4
Sanger	N/A4	32.4	35.1	N/A4	129.8	134.2
		57.9	61.4		261.7	246.6
Total Performance	846.4	906.7	856.5	3,086.2	3,134.3	3,086.4

1	The Generation Group's Donnacona Hydro Facility was offline during the second half of 2014 and throughout 2015. Insurance proceeds were received to compensate for lost revenue.
2	The St Damase Wind Facility achieved commercial operation on December 2, 2014.
3	APUC does not consolidate the operating results from this facility in its financial statements. Production from the facility is included as APUC manages the facility under contract and has an option to acquire a 75% equity interest in the facility in 2016.
4	Natural gas fired co-generation facility.

2015 Fourth Quarter Generation Performance

For the three months ended December 31, 2015, the Generation Group generated 906.7 GW-hrs of electricity as compared to 856.5 GW-hrs during 2014

2015 Annual Report	14
Algonquin Power & Utilities Corp. - Management's Discussion & Analysis

For the quarter, the hydro facilities generated 161.1 GW-hrs of electricity, as compared to 171.6 GW-hrs produced in the same period in 2014, a decrease of 6.1%. Electricity generated represented 98.9% of long-term average resources ("LTAR") as compared to 105.3% during the same period in 2014. The decreased generation is largely attributable to weaker hydrology in the Maritimes and Ontario regions.

For the three months ended December 31, 2015, the wind facilities produced 679.0 GW-hrs of electricity, as compared to 621.7 GW-hrs produced in the same period in 2014, an increase of 9.2%. The higher generation was a result of increased wind resources at Shady Oaks and Minonk Wind Facilities, in addition to the St. Damase and Morse Wind Facilities achieving commercial operation in December 2014 and April 2015, respectively. During the three months ended December 31, 2015, the wind facilities (excluding the St. Damase and Morse Wind Facilities) generated electricity equal to 102.4% of LTAR, as compared to 99.7% during the same period in 2014, due to variability in the wind resource.

For the three months ended December 31, 2015, the solar facilities generated 8.7 GW-hrs of electricity, as compared to 1.8 GW-hrs of electricity in the same period in 2014, an increase of 383.3%. The increase in production is attributable to the new Bakersfield I Solar Facility which achieved commercial operation in accordance with the provisions of the PPA on April 14, 2015. Cornwall's production was 9.5% above its LTAR, as compared to 14.3% below its LTAR in the same period last year. Bakersfield I Solar Facility achieved 71.1% of its LTAR primarily due to an equipment malfunction which damaged the inverter houses, impacting 30% of the facility. Repairs of the damaged inverter houses were completed in the fourth quarter of 2015.

For the three months ended December 31, 2015, the thermal facilities generated 57.9 GW-hrs of electricity, as compared to 61.4 GW-hrs of electricity during the same period in 2014. During the same period, the Windsor Locks Thermal Facility generated 143.0 billion lbs of steam, as compared to 157.3 billion lbs of steam during the same period in 2014.

2015 Twelve Month Generation Performance

For the twelve months ended December 31, 2015, the Renewable Energy Division generated 3,134.3 GW-hrs of electricity as compared to 3,086.4 GW-hrs during 2014.

For the twelve months ended December 31, 2015, the hydro facilities generated 599.6 GW-hrs of electricity, as compared to 618.2 GW-hrs produced in the same period in 2014, a decrease of 3.0%. Electricity generated represented 92.2% of long-term projected average resources, as compared to 95.0% during the same period in 2014. During the twelve months ended December 31, 2015, the Ontario Hydro region achieved production above its LTAR, while the Quebec, Western and Maritime regions were below their respective LTAR. The Quebec region was below its LTAR predominantly due to the Donnaconna Hydro Facility being offline during the year. Excluding the Donnacona Hydro Facility, the Quebec region would have achieved 103% of the long term average hydrological resource.

For the twelve months ended December 31, 2015, the wind facilities produced 2,221.7 GW-hrs of electricity, as compared to 2,208.8 GW-hrs produced in the same period in 2014, an increase of 0.6%. During the twelve months ended December 31, 2015, the wind facilities generated electricity equal to 93.4% of LTAR, as compared to 98.9% during the same period in 2014. The incremental electricity generated from St. Damase and Morse Wind Facilities in 2015 was offset by weaker wind resources at the St. Leon and Senate Wind Facilities.

For the twelve months ended December 31, 2015, the solar facilities generated 51.3 GW-hrs of electricity as compared to 12.8 GW-hrs of electricity produced in the same period in 2014, an increase of 300.8%. The Cornwall Solar Facility's production was equal to 4.1% above its LTAR as compared to 10.3% above its LTAR in the same period last year from its commercial operation date in 2014. The Bakersfield I Solar Facility's production was 17.4% below its LTAR, due to the inverter house malfunction during the year. The increase in production is attributable to the first full year of production at the Cornwall Solar Facility and the new Bakersfield I Solar Facility which achieved COD on April 14, 2015 in accordance with the provisions of the PPA.

For the twelve months ended December 31, 2015, the thermal facilities generated 261.7 GW-hrs of electricity, as compared to 246.6 GW-hrs of electricity during the same period in 2014. During the same period, the Windsor Locks Thermal Facility generated 567.7 billion lbs of steam, as compared to 609.1 billion lbs of steam during the same period in 2014.

2015 Annual Report	15
Algonquin Power & Utilities Corp. - Management's Discussion & Analysis

2015 Generation Group Operating Results

	Three months ended  December 31						Twelve months ended December 31, 2015
(all dollar amounts in $ millions)	2015			2014			2015			2014
Revenue1
Hydro	14.6			16.8			55.7			65.1
Wind	38.7			27.0			118.0			88.9
Solar	1.6			0.7			10.3			5.5
Thermal	8.1			9.0			38.5			43.0
Total Revenue	$	63.0		$	53.5		$	222.5		$	202.5
Less:
Cost of Sales - Energy2	(1.7		)	(1.5		)	(10.3		)	(16.7		)
Cost of Sales - Thermal	(3.6		)	(5.0		)	(17.7		)	(22.6		)
Realized gain/(loss) on hedges3	—			(0.2		)	0.6			3.6
Net Energy Sales	$	57.7		$	46.8		$	195.1		$	166.8
Renewable Energy Credits ("REC")4	6.1			4.0			18.5			13.1
Other Revenue	0.9			1.1			3.8			3.2
Total Net Revenue	$	64.7		$	51.9		$	217.4		$	183.1
Expenses & Other Income
Operating expenses	(15.0		)	(13.0		)	(63.6		)	(55.5		)
Interest and Other income	(0.3		)	0.1			1.2			1.2
HLBV income	12.6			8.9			33.9			27.2
Divisional operating profit	$	62.0		$	47.9		$	188.9		$	156.0

1	While most of the Generation Group's PPAs include annual rate increases, a change to the weighted average production levels resulting in higher average production from facilities that earn lower energy rates can result in a lower weighted average energy rate earned by the division, as compared to the same period in the prior year.
2	Cost of Sales - Energy consists of energy purchases in the Maritime Region to manage the energy sales from the Tinker Facility which is sold to retail and industrial customers under multi-year contracts.
3	See financial statements note 24(b)(iv).
4	Qualifying renewable energy projects receive Renewable Energy Credits ("RECs") for the generation and delivery of renewable energy to the power grid. The energy credit certificates represent proof that 1 MW of electricity was generated from an eligible energy source. The RECs can be traded and the owner of the REC can claim to have purchases of renewable energy. REC revenue is recognized only at the time a generated REC unit is matched up with a previously signed REC sales contract with a third party.  Generated REC units not immediately available to match against a signed contract are recorded as inventory with the offset recorded as a decrease in operating expenses.

2015 Fourth Quarter Operating Results

For the three months ended December 31, 2015, the Generation Group facilities generated $62.0 million of operating profit as compared to $47.9 million during the same period in 2014, which represents an increase of $14.1 million, excluding corporate administration expenses.

2015 Annual Report	16
Algonquin Power & Utilities Corp. - Management's Discussion & Analysis

Highlights of the changes are summarized in the following table:

(all dollar amounts in $ millions)	Three months ended December 31, 2015
Prior Period Operating Profit	$	47.9
Existing Facilities
Hydro Canada: The hydro facilities realized lower production rates at the Quebec and Maritime regions.	(2.6		)
Wind Canada: The St Leon Wind Facility experienced decreased wind resources.	(0.6		)
Wind US: The U.S. wind facilities experienced increased wind resources at the Minonk and Shady Oaks Wind Facilities, and increased market pricing for the sale of Renewable Energy Credits ("RECs"). This was offset by lower wind resources at the Senate and Sandy Ridge Wind Facilities.	5.4
Solar Canada: The Cornwall Solar Facility experienced increased solar resource.	0.5
Thermal: The thermal facilities experienced lower production at both the Windsor Locks and Sanger Thermal Facilities.	(0.4		)
Other	(0.5		)
	1.8
New Facilities
Wind Canada: The increase was due to the St. Damase and Morse Wind Facilities achieving commercial operations on Dec 2014 and April 2015, respectively.	3.6
Solar US: Bakersfield I Solar Facility which achieved commercial operation in accordance with the provisions of the PPA in April 2015.	1.3
	4.9
Foreign Exchange
Increased operating profit as a result of a stronger U.S. dollar.	7.4
Current Period Operating Profit	$	62.0

2015 Annual Report	17
Algonquin Power & Utilities Corp. - Management's Discussion & Analysis

2015 Twelve Month Operating Results

For the twelve months ended December 31, 2015, the Generation Group facilities generated $188.9 million of operating profit as compared to $156.0 million during the same period in 2014, which represents an increase of $32.9 million or 21.1%, excluding corporate administration expenses.

Highlights of the changes are summarized in the following table:

(all dollar amounts in $ millions)	Twelve months ended December 31, 2015
Prior Period Operating Profit	$	156.0
Existing Facilities
Hydro Canada: The decreased operating profit at the hydro facilities were primarily a result of the Donnaconna Hydro Facility being offline for the full year in 2015, lower hydrology, and lower demand in the Maritime region. These items were partially offset by increased hydrology at sites other than Donnaconna in the Quebec region.	(6.1		)
Wind Canada: The St Leon Wind Facility experienced decreased wind resources.	(1.7		)
Wind US: The U.S. wind facilities realized higher pricing on the unhedged portion of energy production, and higher pricing for RECs in the PJM market, partially offset by lower production and resulting lower HLBV income.	7.2
Solar Canada: The increase is due to the Cornwall Solar Facility completing its first full year of production as the site achieved commercial operation on March 27, 2014.	1.0
Thermal: The thermal facilities experienced lower production at both the Windsor Locks and Sanger Thermal Facilities.	(2.2		)
Other	(0.1		)
	(1.9		)
New Facilities
Wind Canada: The increase was due to the St. Damase and the Morse Wind Facilities achieving commercial operations in December 2014 and April 2015, respectively.	11.6
Solar US: The increase was due to operating and HLBV income associated with the Bakersfield I Solar Facility which achieved commercial operation in accordance with the provisions of the PPA in April 2015.	5.6
	17.2
Foreign Exchange
Increased operating profit as a result of a stronger U.S. dollar.	17.6
Current Period Operating Profit	$	188.9

GENERATION BUSINESS GROUP

Development Division

The Development Division works to identify, develop and construct new power generating facilities, as well as to identify, and acquire operating projects that would be complementary and accretive to the Generation Group’s existing portfolio.  The Development Division is focused on projects within North America and is committed to working proactively with all stakeholders including local communities. The Generation Group’s approach to project development and acquisition is to maximize the utilization of internal resources while minimizing external costs. This allows projects to mature to the point where most major elements and uncertainties are quantified and resolved prior to the commencement of project construction.  Major elements and uncertainties of a project include the signing of a PPA, obtaining the required financing commitments to develop the project, completion of environmental and other required permitting, and fixing the cost of the major capital components of the project. It is not until all major aspects of a project are secured that the Generation Group’s Development Division will begin construction or execute an acquisition agreement.

The Generation Group’s Development Division has successfully completed, is constructing and is developing a number of power generation projects.  The projects are as follows:

2015 Annual Report	18
Algonquin Power & Utilities Corp. - Management's Discussion & Analysis

Project Name	Location	Size (MW)	Estimated Capital Cost (millions)		Commercial Operation	PPA Term	Production GW-hrs
Total Project in Construction
Odell Wind Project1	Minnesota	200	$	446.8	2016	20	814.7
Val Eo Wind Project2	Quebec	24	$	70.0	2016/17	20	66.0
Bakersfield II Solar Project3	California	10	$	37.4	2016	20	24.2
Deerfield Wind Project4	Michigan	150	$	419.4	2016	20	555.2
Great Bay Solar Project5	Maryland	75	$	249.1	2016/17	10	152.0
		459	$	1,222.7			1,612.1
Projects in Development
Amherst Island Wind Project	Ontario	75	$	272.5	2017	20	235.0
Chaplin Wind Project	Saskatchewan	177	$	340.0	2017/18	25	720.0
Total Projects in Development		252	$	612.5			955.0
Total in Construction and Development		711	$	1,835.2			2,567.1

1	Total cost of the project is expected to be approximately $322.8 million in U.S. dollars.
2	Size, Estimated Capital Costs, Commercial Operation Date, PPA Term and Production refer solely to Phase I of the Val-Eo Wind Project.
3	Total cost of the project is expected to be approximately $27.0 million in U.S. dollars.
4	The total cost of the project is expected to be approximately $303.0 million in U.S. dollars
5	The total cost of the project is expected to be approximately $180.0 million in U.S. dollars.

Projects Completed

Bakersfield I Solar Facility

The Bakersfield I Solar Facility is a 20 MWac solar powered electric generating facility located in Kern County, California.

The facility is comprised of approximately 85,000 solar panels located on 165 acres of land and is expected to generate 53.3 GW-hrs of energy per year with all energy from the facility being sold to a large investment grade electric utility pursuant to a 20 year PPA.

Construction of the facility commenced in the second quarter of 2014 and the facility was placed in service on December 30, 2014. On April 14, 2015 the facility achieved commercial operation in accordance with the provisions within the PPA. The total cost to complete the facility was U.S. $58.4 million.

The Generation Group has entered into a partnership agreement with a third party where the third party contributed U.S. $22.4 million to the project and in return will receive the majority of the tax attributes.

Morse Wind Facility

The Morse Wind Facility is a 23 MW wind powered electric generating facility located near Morse, Saskatchewan, approximately 180 km west of Regina.

The facility is comprised of approximately 10 turbines spread over three contiguous facilities and is expected to generate 104 GW-hrs of energy per year, with all energy from the project being sold to SaskPower pursuant to a 20 year PPA under the Green Options Partner Program.

Construction of the facility commenced in the third quarter of 2014 and the facility reached commercial operation on April 22, 2015 with all 10 turbines completed and selling power under the provisions of the PPA. The total cost to complete the facility was $81.7 million.

2015 Annual Report	19
Algonquin Power & Utilities Corp. - Management's Discussion & Analysis

Projects in Construction

2015 Annual Report	20
Algonquin Power & Utilities Corp. - Management's Discussion & Analysis

Odell Wind Project

The Odell Wind Project is a 200 MW wind powered electric generating development project located in Cottonwood, Jackson, Martin, and Watonwan counties in Minnesota and the project is being constructed on approximately 23,000 acres of leased land.

The project will be comprised of 100 Vestas V110-2.0 wind turbines and is expected to generate 814.7 GW-hrs of energy per year with all energy, capacity and renewable energy credits from the project sold to Northern States Power Company, a subsidiary of Xcel Energy Inc., which is a diversified utility operating in the Midwest, pursuant to a 20 year PPA.

Construction of the project commenced in the second quarter of 2015. Turbine erection began in early November and the new 115 kV transmission line has been built. The collection system substation work was completed and successfully energized in cooperation with the Transmission Provider in December 2015.

The total costs to complete the project are estimated at approximately U.S. $322.8 million. It is anticipated that the Odell Project will qualify for U.S. federal production tax credits, accordingly the project company has entered into a partnership agreement with third parties (tax equity) to contribute approximately U.S. $180 million to the project in return for the majority of the tax attributes. Construction financing, including a portion that bridges to tax equity's investment, was arranged by the project company during 2015.

The Generation Group's participation in the project will be via a 50% equity interest in a new joint venture with a third party developer. The Company is accounting for the joint venture as an equity method investment since both partners have joint control of the new venture. The Generation Group holds an option to acquire the other 50% interest on commencement of commercial operations, which is expected in the third quarter of 2016.

Val-Éo Wind Project

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

The project will be developed in two phases: Phase I of the project is expected to be completed in 2017 and will comprise of eight 3.0 MW wind turbines and is expected to generate 66.0 GW-hrs of energy per year, with all energy from Phase I of the project sold to Hydro Quebec pursuant to a 20 year PPA; Phase II of the project would entail the development of an additional 101 MW and would be constructed following evaluation of the wind resource at the site, completion of satisfactory permitting and entering into appropriate energy sales arrangements.

All land agreements, construction permits, and authorizations have been obtained for Phase I. After the permitting process was delayed at the provincial level, construction planned in 2015 has been re-evaluated due to the severe weather conditions in the region. The new schedule calls for construction to begin in the second quarter of 2016 as such the project is expected to now reach commercial operations in late 2016 or early 2017. Total costs to complete the project are estimated at approximately $70.0 million.

The Generation Group’s equity interest in the project is subject to final negotiations with the Val-Éo community cooperative but, in any event, will not be less than 25%. It is believed that the first 24 MW phase of the Val-Éo Wind Project will qualify as Canadian Renewable Conservation Expense and therefore the project will be entitled to a refundable tax credit equal to approximately $18.0 million.

Bakersfield II Solar Project

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

The project is located on 64 acres of land and is expected to generate 24.2 GW-hrs of energy per year with all energy from the project sold to the same large investment grade electric utility as Bakersfield I Solar Facility, pursuant to a 20 year PPA.

Construction of the project commenced in the second quarter of 2015. Project permits with the county and an EPC contractor are at an advanced stage. The project has a commercial operations date targeted for the second quarter of 2016.

The total costs to complete the project are estimated at approximately U.S. $27.0 million and are expected to be funded with a combination of senior debt, common equity, and contributions from tax equity investors. Consistent with financing structures utilized for U.S. based renewable energy projects including Bakersfield I Solar, it is anticipated that Bakersfield II Solar will source financing in the amount of approximately 40% of the capital costs from certain tax equity investors.

Deerfield Wind Project

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

2015 Annual Report	21
Algonquin Power & Utilities Corp. - Management's Discussion & Analysis

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

Construction of the project commenced in the fourth quarter of 2015. Over 90% of the private land access roads have been constructed and public road improvements are underway. The main power transformer procurement has been finalized, and engineering for the project is nearing completion. The project has a commercial operations date targeted for the fourth quarter of 2016.

The total costs to complete the project are estimated at approximately U.S. $303.0 million.  It is anticipated that the Deerfield Wind Project will qualify for U.S. federal production tax credits, accordingly, approximately 50% of the permanent project financing is expected to be funded by tax equity investors in return for the majority of the tax attributes.

The Generation Group's interest in the project is via a 50% joint venture with the original developer. The Company is accounting for the joint venture as an equity method investment since both partners have joint control of the new venture. The Generation Group holds an option to acquire the other 50% interest for total contributions, subject to certain adjustments any time prior to the date that is 90 days following commencement of operations.

Great Bay Solar

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

The project is expected to generate 152.0 GW-hrs of energy per year, with all energy sold to the U.S. Government Services pursuant to a 10 year PPA, with a 10 year extension option. All Solar Renewable Energy Credits from the project will be retained by the project company and sold into the Maryland market.

Permitting with the county is underway, and is expected to be completed in the second quarter of 2016. The project has received its Certificate of Public Convenience and Necessity from the State of Maryland Public Service Commission. The EPC contract has been executed, and equipment procurement is in progress, with deliveries to the site beginning in the third quarter of 2016. The project has a commercial operations date targeted for late 2016 or early 2017.

The total costs to complete the project are estimated at approximately U.S. $180.0 million. The Generation Group expects the project will qualify for U.S. federal investment tax credits and accordingly, approximately U.S. $62.0 million of the permanent project financing is expected to be funded by tax equity investors in return for the majority of the tax attributes

Projects in Development

Amherst Island Wind Project

The Amherst Island Wind Project is a 75.0 MW wind powered electric generating development project located on Amherst Island near the village of Stella, approximately 15 kilometers southwest of Kingston, Ontario. In February 2011, the 75 MW project was awarded a Feed-In-Tariff (“FIT”) contract by the OPA as part of the second round of the OPA’s FIT program.

The total costs to complete the project is estimated at approximately $272.5 million. The project is currently contemplated to use Class III wind turbine generator technology. The available wind resource is forecast to produce approximately 235.0 GW-hrs of electrical energy annually, depending upon the final turbine selection for the project. Final negotiations on the turbine supply agreement are ongoing; and engineering, procurement and construction contractor selection is underway. The project has a commercial operations date targeted for 2017.

The Renewable Energy Approval ("REA") was issued on August 24, 2015 following 29 months of review by the Ontario Ministry of Environment. An appeal of the REA has been made to the Environmental Review Tribunal (“ERT”). The appeal process is generally limited to a period of 6 months, although the ERT may grant extensions in appropriate cases. It is anticipated that the hearing will extend beyond 6 months and is likely to conclude in April 2016. Other permitting processes and the engineering and procurement of long-lead time equipment are progressing according to schedule, including the supply of turbines for the project. The project has a planned construction time frame of approximately 12 months.

Chaplin Wind Project

The Chaplin Wind Project is a 177.0 MW wind powered electric generating development project located in the rural municipality of Chaplin, Saskatchewan, 150 km west of Regina, Saskatchewan.

The project will be developed in two phases: Phase I of the project is expected to be completed in 2017 and is expected to generate approximately 35 MW of the total project, with all energy from Phase I of the project sold to SaskPower pursuant to a 25 year PPA; Phase II of the project, which comprises the remaining approximately 142 MW, will be the infill construction phase and will only proceed following evaluation of the wind resource at the site, and completion of satisfactory permitting.

The total costs to complete the project are estimated at approximately $340.0 million but are subject to change depending on turbine selection. Depending on the size of the turbines used, the number of pads will vary from 58 to 70, and energy may vary from 659-766 GW-hrs. Final selection will be based on multiple factors including an assessment of the internal

2015 Annual Report	22
Algonquin Power & Utilities Corp. - Management's Discussion & Analysis

rate of return. The PPA features a rate escalation provision of 0.6% throughout the term of the agreement. The project will take advantage of its favorable location by interconnecting with a nearby 138kV line and will be compliant with SaskPower’s latest interconnection requirements. The project has a commercial operations date targeted for late 2017 or early 2018.

In the first quarter of 2015, the Environmental Impact Statement documentation was submitted and meetings were held with the Ministry of Environment ("SKMOE"). Supplemental reports were submitted in the second and third quarters of 2015. The SKMOE completed the required 30 day public posting period on November 17, 2015, and the EIA is expected to be issued in the second quarter of 2016. The turbine and balance of plant contractor selection will be finalized upon signing of the turbine supply agreement, which is in the final stages, though dependent on the SMKOE permit approval.

DISTRIBUTION BUSINESS GROUP

The Distribution Group operates rate-regulated utilities providing distribution services to approximately 489,000 connections, excluding the Park Water System, in the natural gas, electric, water and wastewater sectors.  The Distribution Group's strategy is to grow its business organically and through business development activities while using prudent acquisition criteria.  The Distribution Group believes that its business results are maximized by building constructive regulatory and customer relationships, and enhancing community connections.

Utility System Type	December 31, 2015			December 31, 2014
(all dollar amounts in U.S. $ millions)	Assets		Connections	Assets		Connections
Electricity	$	343.2	93,000	$	325.0	93,000
Natural Gas	783.0		292,000	726.0		292,000
Water and Wastewater	254.7		104,000	261.2		103,000
Total	$	1,380.9	489,000	$	1,312.2	488,000
Accumulated Deferred Income Taxes	$	110.3		$	79.6

The Distribution 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 93,000 connections in the states of California and New Hampshire.

The natural gas distribution systems are comprised of regulated natural gas distribution utility systems and serve approximately 292,000 connections located in the states of New Hampshire, Illinois, Iowa, Missouri, Georgia, and Massachusetts.

The water and wastewater distribution systems are comprised of regulated water distribution and wastewater collection utility systems and serve approximately 104,000 connections located in the states of Arkansas, Arizona, Texas, Illinois, and Missouri. On January 8, 2016, the Distribution Group completed its acquisition of the Park Water System which is comprised of two water and wastewater facilities in California and one facility in Montana. This acquisition adds another 74,000 connections to the Distribution Group's present water and wastewater footprint.

2015 Fourth Quarter Usage Results

Electric Distribution Systems	Three months ended December 31
	2015	2014
Average Active Electric Connections For The Period
Residential	80,000	80,000
Commercial and Industrial	12,000	12,000
Total Average Active Electric Connections For The Period	92,000	92,000
Customer Usage (GW-hrs)
Residential	135.8	134.9
Commercial and Industrial	220.3	230.5
Total Customer Usage (GW-hrs)	356.1	365.4

For the three months ended December 31, 2015 the electric distribution systems' usage totalled 356.1 GW-hrs, as compared to 365.4 GW-hrs for the same period in 2014, a decrease of 9.3 GW-hrs.

Natural Gas Distribution Systems	Three months ended December 31,
	2015	2014
Average Active Natural Gas Connections For The Period
Residential	248,000	248,000
Commercial and Industrial	27,000	27,000
Total Average Active Natural Gas Connections For The Period	275,000	275,000
Customer Usage (MMBTU)
Residential	3,002,000	3,918,000
Commercial and Industrial	2,362,000	2,885,000
Total Customer Usage (MMBTU)	5,364,000	6,803,000

For the three months ended December 31, 2015, usage at the natural gas distribution systems totalled 5,364,000 MMBTU, as compared to 6,803,000 MMBTU during the same period in 2014, a decrease of 1,439,000 MMBTU, or 21.2%. The

2015 Annual Report	23
Algonquin Power & Utilities Corp. - Management's Discussion & Analysis

decrease in natural gas usage, as compared to the same period in 2,014, can primarily be attributed to a lower number of heating degree days experienced in the EnergyNorth and Midstates Gas Systems service territories, as compared to the same period in 2,014.

Water and Wastewater Distribution Systems	Three months ended December 31,
	2015	2014
Average Active Connections For The Period
Wastewater connections	40,000	40,000
Water distribution connections	59,000	58,000
Total Average Active Connections For The Period	99,000	98,000
Gallons Provided
Wastewater treated (millions of gallons)	532	535
Water sold (millions of gallons)	1,971	1,940
Total Gallons Provided	2,503	2,475

During the three months ended December 31, 2015, the water and wastewater distribution systems provided approximately 1,971 million gallons of water to its customers and treated approximately 532 million gallons of wastewater, which was relatively consistent with 1,940 million gallons of water provided and 535 million gallons of wastewater treated during the same period in 2014.

2015 Annual Report	24
Algonquin Power & Utilities Corp. - Management's Discussion & Analysis

2015 Distribution Group Operating Results

	Three months ended December 31,						Three months ended December 31,
	2015 U.S. $ (millions)			2014 U.S. $ (millions)			2015 Can $ (millions)			2014 Can $ (millions)
Revenue
Utility electricity sales and distribution	40.8			47.8			54.6			54.4
Less: Cost of Sales – Electricity	(23.1		)	(29.9		)	(30.9		)	(34.2		)
Net Utility Sales - Electricity	$	17.7		$	17.9		$	23.7		$	20.2
Utility natural gas sales and distribution	80.1			102.5			107.5			116.7
Less: Cost of Sales – Natural Gas	(36.4		)	(65.6		)	(48.9		)	(74.8		)
Net Utility Sales - Natural Gas	$	43.7		$	36.9		$	58.6		$	41.9
Net Utility Sales - Water Distribution & Wastewater Treatment	15.3			15.0			20.4			18.6
Gas Transportation	5.7			6.8			7.6			7.6
Other Revenue	0.1			3.0			0.2			3.4
Net Utility Sales	$	82.5		$	79.6		$	110.5		$	91.7
Operating expenses	(39.2		)	(39.8		)	(52.3		)	(46.0		)
Other income	0.8			0.8			1.1			0.9
Distribution Group operating profit	$	44.1		$	40.6		$	59.3		$	46.6

2015 Fourth Quarter Operating Results

For the three months ended December 31, 2015, the Distribution Group reported an operating profit of U.S. $44.1 million, as compared to U.S. $40.6 million for the comparable period in the prior year. The increase is primarily due to implementation of final rates at the EnergyNorth, Missouri, and Illinois Gas Systems. Measured in Canadian dollars, the group's operating profit was $59.3 million, as compared to $46.6 million during the same period in 2014, which represents an increase of $12.7 million, excluding corporate administration expenses.

Highlights of the changes are summarized in the following table:

2015 Annual Report	25
Algonquin Power & Utilities Corp. - Management's Discussion & Analysis

(all dollar amounts in $ millions)	Three months ended December 31, 2015
Prior Period Operating Profit	$	46.6
Existing Facilities
Electric Distribution Systems: The decrease in net utility sales at the Granite State Electric System is due to decreased GW-hrs used by commercial customers as compared to the same period in the previous year, partially offset by an increase in net utility sales at the Calpeco Electric System for a revenue component that is not included in the decoupling mechanism.	(0.2		)
Natural Gas Distribution Systems: Primarily due to increased revenues at the New England Gas System as a result of tracking mechanisms.	3.2
Water Distribution & Wastewater Treatment Systems: The water utilities' performance, excluding rate case impacts, was in line with the prior year.	—
Other Income: Decrease is primarily due to reduced billings for contracted services as compared to the same period in 2014.	(2.8		)
	0.2
Rate Cases
Natural Gas Distribution Systems: Successful implementation of new rates at the EnergyNorth and the Missouri Natural Gas System.	3.3
Water Distribution & Wastewater Treatment Systems: Successful implementation of new rates at the LPSCo Water System.	0.2
	3.5
Foreign Exchange
Increased operating profit as a result of a stronger U.S. dollar.	9.0
Current Period Operating Profit	$	59.3

2015 Twelve Month Usage Results

Electric Distribution Systems	Twelve months ended December 31
	2015	2014
Average Active Electric Connections For The Period
Residential	80,000	79,000
Commercial and Industrial	12,000	12,000
Total Average Active Electric Connections For The Period	92,000	91,000
Customer Usage (GW-hrs)
Residential	554.9	557.4
Commercial and Industrial	898.7	933.4
Total Customer Usage (GW-hrs)	1,453.6	1,490.8

For the twelve months ended December 31, 2015 the electric distribution systems' usage totalled 1,453.6 GW-hrs, as compared to 1,490.8 GW-hrs for the same period in 2014, a decrease of 37.2 GW-hrs.

2015 Annual Report	26
Algonquin Power & Utilities Corp. - Management's Discussion & Analysis

Natural Gas Distribution Systems	Twelve months ended December 31
	2015	2014
Average Active Natural Gas Connections For The Period
Residential	248,000	248,000
Commercial and Industrial	27,000	26,000
Total Average Active Natural Gas Connections For The Period	275,000	274,000
Customer Usage (MMBTU)
Residential	17,385,000	18,915,000
Commercial and Industrial	12,460,000	12,673,000
Total Customer Usage (MMBTU)	29,845,000	31,588,000

For the twelve months ended December 31, 2015, usage at the natural gas distribution systems totalled 29,845,000 MMBTU, as compared to 31,588,000 MMBTU during the same period in 2014,a decrease of 1,743,000 MMBTU, or 5.5%. The decrease in natural gas usage, as compared to the same period in 2014, can be primarily attributed to a decrease in heating degrees days experienced in the EnergyNorth and Midstates Gas Systems service territories as compared to 2014.

Water and Wastewater Distribution Systems	Twelve months ended December 31,
	2015	2014
Average Active Connections For The Period
Wastewater connections	40,000	39,000
Water distribution connections	59,000	58,000
Total Average Active Connections For The Period	99,000	97,000
Gallons Provided
Wastewater treated (millions of gallons)	2,168	2,127
Water sold (millions of gallons)	8,457	8,310
Total Gallons Provided	10,625	10,437

During the twelve months ended December 31, 2015, the water and wastewater distribution systems provided approximately 8,457 million gallons of water to its customers and treated approximately 2,168 million gallons of wastewater, as compared to 8,310 million gallons of water and 2,127 million gallons of wastewater during the same period in 2014. The increase in water sold can be primarily attributed to the acquisition of the White Hall Water System on May 30, 2014. The increase in wastewater treated is primarily attributed to an increase in wastewater treated at our sewer utilities located in the state of Arizona.

2015 Annual Report	27
Algonquin Power & Utilities Corp. - Management's Discussion & Analysis

2015 Twelve Month Operating Results

	Twelve months ended December 31,						Twelve months ended December 31,
	2015 U.S. $ (millions)			2014 U.S. $ (millions)			2015 Can $ (millions)			2014 Can $ (millions)
Revenue
Utility electricity sales and distribution	175.6			185.1			224.1			204.7
Less: Cost of Sales – Electricity	(103.3		)	(108.8		)	(131.6		)	(120.5		)
Net Utility Sales - Electricity	$	72.3		$	76.3		$	92.5		$	84.2
Utility natural gas sales and distribution	339.9			378.2			431.3			419.9
Less: Cost of Sales – Natural Gas	(172.0		)	(234.8		)	(217.3		)	(261.1		)
Net Utility Sales - Natural Gas	$	167.9		$	143.4		$	214.0		$	158.8
Net Utility Sales - Water Distribution & Wastewater Treatment	61.3			58.8			78.4			66.4
Gas Transportation	26.4			23.5			33.5			26.1
Other Revenue	12.1			5.1			15.8			5.7
Net Utility Sales	$	340.0		$	307.1		$	434.2		$	341.2
Operating expenses	(168.3		)	(160.7		)	(213.8		)	(178.2		)
Other income	3.2			2.9			4.0			3.4
Distribution Group operating profit	$	174.9		$	149.3		$	224.4		$	166.4

For the twelve months ended December 31, 2015, the Distribution Group reported an operating profit of U.S. $174.9 million, as compared to U.S. $149.3 million for the comparable period in the prior year. The increase is primarily due to the implementation of higher rates as a result of successful rate cases at the EnergyNorth, Missouri, Illinois, and Peach State Gas Systems, and revenues from contracted services as compared to the same period in 2014. Measured in Canadian dollars, the group's operating profit was $224.4 million, as compared to $166.4 million for the comparable period in the prior year.

Highlights of the changes are summarized in the following table:

2015 Annual Report	28
Algonquin Power & Utilities Corp. - Management's Discussion & Analysis

(all dollar amounts in $ millions)	Twelve months ended December 31, 2015
Prior Period Operating Profit	$	166.4
Existing Facilities
Electric Distribution Systems: lower demand at Granite State Electric System and increased operating expenses at the Calpeco Electric System pertaining to rate case administration	(3.0		)
Natural Gas Distribution Systems: increase in transportation revenues	3.3
Water Distribution & Wastewater Treatment Systems: increased operating costs at the water and wastewater facilities	(0.3		)
Other Income: increased billings for contracted services as compared to the same period in 2014	7.0
	7.0
New Facilities
Water & Wastewater Distribution and Treatment Systems: Acquisition of the White Hall Water and Wastewater System	0.5
Other Income	0.2
	0.7
Rate Cases
Electric Distribution Systems: In 2014 the Granite State Electric System retroactively recognized rates pertaining to its 2014 rate case settlement. A similar adjustment was not made in 2015.	(2.4		)
Natural Gas Distribution Systems: Successful implementation of new rates at the EnergyNorth, Illinois, Georgia and the Missouri Natural Gas Systems	19.9
Water Distribution & Wastewater Treatment Systems: Successful implementation of new rates at the LPSCo Water System	1.3
	18.8
Foreign Exchange
Increased operating profit as a result of a stronger U.S. dollar.	31.5
Current Period Operating Profit	$	224.4

2015 Annual Report	29
Algonquin Power & Utilities Corp. - Management's Discussion & Analysis

Regulatory Proceedings

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

Utility	State	Regulatory Proceeding Type	Rate Request U.S. $ (millions)	Current Status
Completed Rate Cases
Illinois Gas System	Illinois	General Rate Case	$5.7	Final Order issued in February 2015 approving a U.S. $4.6 million rate increase effective February 2015.
Pine Bluff Water System	Arkansas	General Rate Case	$2.5	Final Order issued in March 2015 approving a U.S. $1.1 million rate increase effective March 15, 2015.
EnergyNorth System	New Hampshire	General Rate Case	$16.1	Application filed August 2014; a temporary rate increase was approved on November 21, 2014 allowing a U.S. $7.4 million interim increase effective December 1, 2014 retroactive to November 1, 2014 upon approval of permanent rates. A final permanent rate decision was issued June 2015, allowing for a U.S. $12.4 million rate increase effective July 1, 2015.
Peach State Gas System	Georgia	GRAM	$3.4	Application filed on October 2015 seeking a U.S. $3.4 million revenue increase. Commission approval was received in February 2016, allowing for a U.S. $2.7 million rate increase effective March 1, 2016.
New England Gas System	Massachusetts	General Rate Case	$11.8	Final Order issued in February 2016 approving a U.S. $8.3 million rate increase effective March 2016.
Pending Rate Cases
CalPeco Electric System	California	General Rate Case	$13.6	Application filed in May 2015 seeking a U.S. $13.6 million revenue increase effective January 2016. A final permanent rate decision is expected in Q2 2016.
Black Mountain Sewer System	Arizona	General Rate Case	$0.4	Application filed in June 2015 seeking a U.S. $0.4 million revenue increase. A final permanent rate decision is expected in Q3 2016.
Rio Rico Water/Sewer System	Arizona	General Rate Case	$0.9	Application filed in October 2015 seeking a U.S. $0.9 million revenue increase. A final permanent rate decision is expected in Q4 2016.
Bella Vista Water System	Arizona	General Rate Case	$1.6	Application filed in October 2015 seeking a U.S. $1.6 million revenue increase. A final permanent rate decision is expected in Q4 2016.

Completed Rate Cases

On March 31, 2014, the Midstates Gas System filed a rate case with the Illinois Commerce Commission ("ICC") seeking an increase in revenue of U.S. $5.7 million. The filing was based on a test year that includes anticipated capital expenditures within 2014 and 2015. An Order was issued on February 11, 2015, approving a U.S. $4.6 million revenue increase effective February 20, 2015.

On July 2, 2014, Pine Bluff Water System filed an application with the Arkansas Public Service Commission ("APSC") seeking an increase in revenue of U.S. $2.5 million based on a test year ending January 31, 2014, with pro forma changes to certain operating expenses and rate base capital additions. The previous test year ended September 30, 2009. An Order was issued on March 12, 2015, approving a U.S. $1.1 million revenue increase effective March 15, 2015.

2015 Annual Report	30
Algonquin Power & Utilities Corp. - Management's Discussion & Analysis

On August 1, 2014, the EnergyNorth Natural Gas System in New Hampshire filed an application for an increase in revenue of U.S. $16.1 million, or approximately 9.6%. A temporary rate increase was approved on November 21, 2014, allowing a U.S. $7.4 million interim rate increase effective December 1, 2014, retroactive to November 2014 upon approval of permanent rates. On June 26, 2015, an Order was issued approving a settlement agreement allowing for a U.S. $12.4 million revenue increase effective July 1, 2015.

On October 1, 2015, the Peach State Gas System filed an application for an increase in revenue of U.S. $3.4 million in its annual GRAM filing with the Georgia Public Service Commission. New rates were to be effective February 1, 2016, for the period February 1, 2016, through January 31, 2017 to reflect changes in revenue levels and cost of service. The GRAM uses a 12 month base period ending June 2015 (historic test year), with adjustments for the 12 months ending September 2016 (forward looking test year). Commission approval was received in February 2016, allowing for a U.S. $2.7 million rate increase effective March 1, 2016. The difference from the original proposed amount was due to tax depreciation rates and the use of revised inflationary factors applied to operating expenses.

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

Pending Rate Cases and Other Applications of Note

On May 1, 2015, the CalPeco Electric System filed an application with the California Public Utilities Commission ("CPUC") seeking an increase in revenue of U.S. $13.6 million, or 17.3%, based on a test year ending December 31, 2014, with pro forma changes to certain operating expenses and rate base capital additions. The increase reflects a requested return on equity of 10.5% and a debt/equity structure of 45%/55%. The previous test year ended December 31, 2011. A final permanent rate decision is expected in the second quarter of 2016, however, new permanent rates are proposed to be retroactively effective in the first quarter of 2016.

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

On October 28, 2015, the Rio Rico Water and Wastewater System filed a rate case and financing application. The application seeks a combined increase in revenue requirement of U.S. $0.9 million, based on a test year ending December 31, 2014, a combined rate base of U.S. $14.2 million, 10.8% ROE, and 70% equity, for an overall rate of return of 8.6%. The proposed revenue increases are U.S. $0.7 million, or 22.6%, for the water division and U.S. $0.2 million, or 15.3%, for the wastewater division. This rate case is primarily needed to recover increased operating costs and capital improvements. It also includes approval for the fair value Arizona rate evaluation model (“FARE”), a purchased power adjuster mechanism (“PPAM”) and a property tax adjuster mechanism (“PTAM”). The FARE allows for a periodic update of all components in the revenue requirement (subject to an earnings band). A final decision and implementation of new rates is expected for the fourth quarter of 2016. Its previous rate case was based on a test year ending February 2012.

On October 28, 2015, the Bella Vista Water System filed a rate case and financing application. The application seeks an increase in revenue requirement of U.S. $1.6 million, or 33.6%, based on a test year ending December 31, 2014, a rate base of U.S. $13.2 million, 11.6% ROE, and 70% equity, for an overall rate of return of 9.16%. This rate case is primarily needed to recover increased operating costs and capital improvements. It also includes approval for the FARE, a PPAM and a PTAM. A final decision and implementation of new rates is expected for the fourth quarter of 2016. Its previous rate case was based on a test year ending March 2009.

Other Applications

In April 2014, the CalPeco Electric System filed an application with the CPUC seeking to recover U.S. $2.1 million recorded within its Vegetation Management Memorandum Account ("VMMA") during the period May 2012 through December 2012. A proposed decision was issued in September 2015 supporting 100% recovery of the VMMA costs. This was followed by an Order from the CPUC on October 22, 2015 supporting the cost recovery.

2015 Annual Report	31
Algonquin Power & Utilities Corp. - Management's Discussion & Analysis

Related to the above CalPeco Electric System rate application are two additional applications in California. The first is an Application filed with the CPUC on April 17, 2015 for the issuance of a Certificate of Public Convenience and Necessity (“CPCN”) to acquire, own and operate a solar power generation station with a total generation capacity of up to 60MW (the “Solar Project”). The application requested authorization for rate recovery of the costs that the CalPeco Electric System will incur to acquire, own, and operate the Solar Project. The second is an Application filed on April 24, 2015 with the CPUC requesting authority to enter into a new multi-year Services Agreement with NV Energy commencing January 2016 and authority to recover the costs it will incur under the 2016 NV Energy Services Agreement as energy purchase costs. This new PPA is required as an existing PPA with NV Energy expires at the end of 2015. The Distribution Group believes these two applications allow the CalPeco Electric System to continue procurement of its energy supply in a cost-effective manner for its customers and allow the utility to meet its Renewables Portfolio Standard requirements. An Order approving the Solar Application (revised to 50MW in a settlement) was issued in December 2015. An Order approving the new PPA was issued in January 2016.

The EnergyNorth Natural Gas System in New Hampshire recently filed three applications with the New Hampshire Public Utilities Commission to obtain the franchise rights to provide gas to new territories. One was filed in July 2015 seeking approval to obtain the franchise rights to the Town of Hanover and City of Lebanon. This docket is expected to conclude in the second quarter of 2016. A second was filed in August 2015 seeking the franchise rights to the towns of Pelham and Windham. This docket is expected to conclude in the second quarter of 2016. A third application was filed in October 2015 to serve the towns of Jaffrey, Rindge, Swanzey, and Winchester. This docket is expected to conclude in the second quarter of 2016.

Park Water System Acquisition Approvals

On September 19, 2014, the Distribution Group announced an agreement to acquire the stock of Western Water Holdings, a company which through its subsidiaries owns three regulated water utilities engaged in the production, treatment, storage, distribution, and sale of water in Southern California and Western Montana.  The three utilities collectively serve approximately 74,000 customer connections and have more than 1,000 miles of distribution mains.  The acquisition closed on January 8, 2016.

An approval application was filed on November 24, 2014, with the CPUC seeking approval for Liberty Utilities Co. to effectively acquire the two water utilities located in California. The CPUC approved a Settlement Agreement supporting the transaction in December 2015.  An application was also filed on December 15, 2014, with the Montana Public Service Commission seeking review of the transaction.  As regulatory approval for purchase of parent company stock is not expressly required in Montana, the application was withdrawn concurrent with the transaction closing.

TRANSMISSION BUSINESS GROUP

In 2014, APUC created the Transmission Group which the Company believes complements the growth of the Generation and Distribution Groups. The Transmission Group is responsible for identifying, evaluating, and capitalizing upon natural gas pipeline and electric transmission asset opportunities in North America.

Northeast Expansion Pipeline

In November 2014, the Transmission Group announced that it had entered into an agreement to participate in a natural gas pipeline transmission project in partnership with Kinder Morgan, Inc. Specifically, Kinder Morgan Operating L.P. “A,” a wholly owned subsidiary of Kinder Morgan, Inc., and Liberty Utilities (Pipeline & Transmission) Corp., a wholly owned subsidiary of APUC, have agreed to form a new entity ("Northeast Expansion LLC") to undertake the development, construction and ownership of a natural gas transmission pipeline to be located between Wright, New York and Dracut, Massachusetts (the “NEP Project”).

Under the agreement, APUC will initially subscribe for a 2.5% interest in NEP Project. APUC also has an opportunity to increase its participation to 10%.

In July 2015, Kinder Morgan announced that it is proceeding with the NEP Project subject to receiving all applicable permits. In late September 2015, the NEP Project (through its developer - Tennessee Gas Pipeline) announced an Open Season designed to attract additional power generation loads in the Northeast. This is in concert with several states which include New Hampshire, Massachusetts and Connecticut moving forward with regulatory initiatives to support the pass through of power generators long term pipeline capacity costs to support further infrastructure development. The commissions for these states have approved the gas distribution utility's contractual commitments to the NEP Project.

Given the proposed route of the project, the Distribution Group will also look to economically expand its gas distribution utility footprint in New Hampshire as well to serve over twenty new communities with natural gas service.

Northeast Supply Pipeline

In December 2015, the Transmission Group announced that it had reached closure in negotiations with subsidiaries of Kinder Morgan to acquire equity investment rights in a new entity ("Northeast Supply Pipeline LLC ("NSP Project")) to undertake the

2015 Annual Report	32
Algonquin Power & Utilities Corp. - Management's Discussion & Analysis

development, construction and ownership of a natural gas transmission pipeline from northeastern Pennsylvania to a point near Wright, New York.

The joint venture could involve a 30 inch diameter, 132-mile greenfield pipeline with a design capacity of up to approximately 1.2 billion cubic feet per day. The project could also include 41 miles of looping of the existing Tennessee 300 Line system in Pennsylvania. The Transmission Group has secured a 4% initial participation right, with additional options to increase its participation to a 10% total ownership interest.

FERC Application

The NEP Project and NSP Project developer, Tennessee Gas Pipeline, filed a combined FERC application for a Certificate of Public Convenience and Necessity along with a complete Environmental Review in November 2015. The estimated project cost for both the NEP Project and NSP Project included in this FERC application was USD $5.2 billion. The total capital investment for the Transmission Group assuming the Company exercises its right to subscribe for 10% of each pipeline project is estimated to be U.S. $520 million. A November 2016 FERC order has been requested and a November 2018 project in service date is planned.

APUC: CORPORATE AND OTHER EXPENSES

	Three months ended December 31,						Year ended December 31,
(all dollar amounts in $ millions)	2015			2014			2015			2014
Corporate and other expenses:
Administrative expenses	$	13.2		$	10.5		$	40.7		$	34.7
(Gain)/Loss on foreign exchange	0.3			0.3			(2.6		)	(1.1		)
Interest expense	17.4			14.1			66.0			62.4
Interest, dividend and other Income1	(2.1		)	(0.5		)	(4.0		)	(3.2		)
Write down of long lived assets and loss/(gain) on disposal	1.1			0.2			2.9			8.0
Acquisition-related costs	0.5			1.6			1.8			2.6
(Gain)/Loss on derivative financial instruments	—			2.0			(2.2		)	1.4
Income tax expense	11.8			3.7			43.7			16.8

1 Excludes income directly pertaining to the Generation and Distribution Groups (disclosed in the relevant sections).

2015 Annual Corporate and Other Expenses

During the year ended December 31, 2015, administrative expenses totalled $40.7 million, as compared to $34.7 million in the same period in 2014. The $6.0 million increase primarily relates to additional costs incurred to administer APUC's operations as a result of the company's growth and a stronger U.S. dollar.

For the year ended December 31, 2015, interest expense totalled $66.0 million, as compared to $62.4 million in the same period in 2014. The increased interest expense is a result of new indebtedness incurred during the first half of 2015 used to partially finance new acquisitions and fund other growth initiatives and a stronger U.S. dollar.

For the year ended December 31, 2015, interest, dividend, equity and other income totalled $4.0 million, as compared to $3.2 million in the same period in 2014, an increase of $0.8 million due to increased dividends from APUC’s share investment in the Kirkland Thermal Facility.

For the year ended December 31, 2015, acquisition related costs totalled $1.8 million, as compared to $2.6 million in the same period in 2014. Acquisition related costs will vary from period to period depending on the level of activity and complexity associated with various acquisitions.

For the year ended December 31, 2015, the gain on derivative financial instruments totalled $2.2 million, as compared to a loss of $1.4 million in the same period in 2014. The increase was primarily driven by derivative gains on hedges to purchase electricity for resale at contracted rates that differ from the market rate.

An income tax expense of $43.7 million was recorded in the year ended December 31, 2015, as compared to an income tax expense of $16.8 million during the same period in 2014.  The increase in income tax expense for the year ended December 31, 2015 is primarily due to increased earnings from operations, increased deferred taxes on HLBV income, a stronger U.S. dollar, a one-time non-cash charge of $2.7 million to deferred income taxes as a result of an arrangement reached with the CRA

2015 Annual Report	33
Algonquin Power & Utilities Corp. - Management's Discussion & Analysis

related to the Unit Exchange Transaction (see Operational Risk Management - Tax Risk and Uncertainty), and other items permanently non-deductible for tax purposes.

2015 Fourth Quarter Corporate and Other Expenses

During the quarter ended December 31, 2015, administrative expenses totalled $13.2 million, as compared to $10.5 million in the same period in 2014. The $2.7 million increase primarily relates to additional costs incurred to administer APUC's operations as a result of the company's growth as well as a stronger U.S. dollar.

For the quarter ended December 31, 2015, interest expense totalled $17.4 million, as compared to $14.1 million in the same period in 2014. The increased interest expense is a result of new indebtedness incurred during the first half of 2015 used to partially finance new acquisitions and fund other growth initiatives and a stronger U.S. dollar.

For the quarter ended December 31, 2015, interest, dividend, equity and other income totalled $2.1 million, as compared to $0.5 million in the same period in 2014. The increase in interest, dividend and other income of $1.6 million primarily consists of increased dividends from APUC’s share investment in the Kirkland Thermal Facility.

For the quarter ended December 31, 2015, loss on derivative financial instruments totalled nil, as compared to a loss of $2.0 million in the same period in 2014. The increase was primarily driven by derivative gains on hedges to purchase electricity for resale at contracted rates that differ from the market rate.

An income tax expense of $11.8 million was recorded in the three months ended December 31, 2015, as compared to an income tax expense of $3.7 million during the same period in 2014.  The increase in income tax expense for the quarter ended December 31, 2015 is primarily due to increased earnings from operations, increased deferred taxes on HLBV income, and a stronger U.S. dollar.

NON-GAAP PERFORMANCE MEASURES

Reconciliation of Adjusted EBITDA to net earnings

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

	Three months ended December 31,						Year ended December 31,
(all dollar amounts in $ millions)	2015			2014			2015			2014
Net earnings attributable to shareholders	$	38.0		$	31.6		$	117.5		$	75.7
Add (deduct):
Net earnings / (loss) attributable to the non-controlling interest, exclusive of HLBV	0.6			0.5			2.0			5.0
Loss from discontinued operations, net of tax	0.1			1.5			1.0			2.1
Income tax expense	11.8			3.7			43.7			16.8
Interest expense	17.4			14.1			66.0			62.4
Other losses / (gains)	(2.1		)	—			(5.1		)	—
Write-down of long lived assets and loss on disposal	1.1			0.2			2.9			8.0
Acquisition related costs	0.5			1.6			1.8			2.6
(Gain) / loss on derivative financial instruments	—			2.0			(2.2		)	1.4
Realized gain / (loss) on energy derivative contracts	—			(0.2		)	0.6			3.6
(Gain) / loss on foreign exchange	0.3			0.3			(2.6		)	(1.1		)
Depreciation and amortization	41.9			29.0			149.8			114.0
Adjusted EBITDA	$	109.6		$	84.3		$	375.4		$	290.5

Hypothetical Liquidation at Book Value (“HLBV”) represents the value of net tax attributes earned by the Generation Group in the period from electricity generated by certain of its U.S. wind power and U.S. solar generation facilities. HLBV earned in the three and twelve months ended December 31, 2015 amounted to approximately $12.6 million and $33.9 million, respectively.

2015 Annual Report	34
Algonquin Power & Utilities Corp. - Management's Discussion & Analysis

Reconciliation of adjusted net earnings to net earnings

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

The following table shows the reconciliation of net earnings to adjusted net earnings exclusive of these items:

	Three months ended December 31,					Year ended December 31,
(all dollar amounts in $ millions)	2015		2014			2015			2014
Net earnings attributable to shareholders	$	38.0	$	31.6		$	117.5		$	75.7
Add (deduct):
(Gain) / Loss from discontinued operations, net of tax	0.1		1.5			1.0			2.1
(Gain) / Loss on derivative financial instruments, net of tax	—		1.2			(1.3		)	0.8
Realized gain / (loss) on derivative financial instruments, net of tax	—		(0.5		)	(0.8		)	0.7
Write-down long lived assets	1.1		0.2			2.9			8.0
Deferred tax expense due to CRA agreement related to the Unit Exchange Transaction	—		—			2.7			—
(Gain) / Loss on foreign exchange, net of tax	0.2		0.2			(1.6		)	(0.7		)
Acquisition costs, net of tax	0.3		1.0			1.1			1.6
Adjusted net earnings	$	39.7	$	35.2		$	121.5		$	88.2
Adjusted net earnings per share	$	0.15	$	0.14		$	0.46		$	0.37

For the year ended December 31, 2015, adjusted net earnings totalled $121.5 million, as compared to adjusted net earnings of $88.2 million, an increase of $33.3 million as compared to the same period in 2014. The increase in adjusted net earnings for the year ended December 31, 2015 is primarily due to higher income from operations partially offset by higher depreciation and amortization expense as compared to 2014.

For the three months ended December 31, 2015, adjusted net earnings totalled $39.7 million, as compared to adjusted net earnings of $35.2 million, an increase of $4.5 million as compared to the same period in 2014. The increase in adjusted net earnings for the three months ended December 31, 2015 is primarily due to increased earnings from operations partially offset by higher depreciation and amortization expense as compared to 2014.

2015 Annual Report	35
Algonquin Power & Utilities Corp. - Management's Discussion & Analysis

Reconciliation of adjusted funds from operations to cash flows from operating activities

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

The following table shows the reconciliation of funds from operations to adjusted funds from operations exclusive of these items:

	Three months ended December 31,						Year ended December 31,
(all dollar amounts in $ millions)	2015			2014			2015		2014
Cash flows from operating activities	$	94.3		$	96.5		$	261.9	$	192.7
Add (deduct):
Changes in non-cash operating items	(17.7		)	(33.1		)	11.1		0.5
Cash used in discontinued operation	0.1			0.9			1.8		1.7
Production based cash contributions from non-controlling interests	—			—			10.8		9.0
Acquisition costs	0.5			1.6			1.8		2.6
Adjusted funds from operations	$	77.2		$	65.9		$	287.4	$	206.5
Adjusted funds from operations per share	0.30			0.27			1.15		0.92

For the year ended December 31, 2015, adjusted funds from operations totalled $287.4 million, as compared to adjusted funds from operations of $206.5 million, an increase of $80.9 million as compared to the same period in 2014.

For the three months ended December 31, 2015, adjusted funds from operations totalled $77.2 million, as compared to adjusted funds from operations of $65.9 million, an increase of $11.3 million as compared to the same period in 2014.

SUMMARY OF PROPERTY, PLANT, AND EQUIPMENT EXPENDITURES

	Three months ended December 31,				Year ended December 31,
(all dollar amounts in $ millions)	2015		2014		2015		2014
GENERATION GROUP	$	4.8	$	60.1	$	56.0	$	201.1
DISTRIBUTION GROUP	$	33.7	$	77.4	$	141.4	$	176.8
Corporate	$	3.8	$	4.3	$	6.8	$	54.5
Total	$	42.3	$	141.8	$	204.2	$	432.4

2015 Fourth Quarter Property Plant and Equipment Expenditures

During the three months ended December 31, 2015, the Generation Group incurred capital expenditures of $4.8 million, as compared to $60.1 million during the comparable period in 2014. The capital expenditures primarily relate to continued construction at the Bakersfield II Solar Project, as well as development spending at the Great Bay Solar Project and the Amherst Wind Project, as compared to the prior year which included spend as it related to the completion of the St Damase Wind Facility, and on-going construction of the Morse Wind and Bakersfield I Solar Facilities.

During the three months ended December 31, 2015, the Distribution Group invested $33.7 million (U.S. $29.9 million) in capital expenditures, as compared to $77.4 million (U.S. $68.0 million) during the comparable period in 2014. The Distribution Group’s investment was primarily related to reliability enhancements, improvements and replenishment opportunities, and leak prone pipe replacements, leak repairs and pipeline corrosion protection systems relating to safety and reliability at the gas systems.

2015 Twelve Month Property Plant and Equipment Expenditures

During the twelve months ended December 31, 2015, the Generation Group incurred capital expenditures of $56.0 million, as compared to $201.1 million during the comparable period in 2014. The Generation Group's capital expenditures in 2015

2015 Annual Report	36
Algonquin Power & Utilities Corp. - Management's Discussion & Analysis

primarily relate to the completion of the Bakersfield I Solar and Morse Wind Facilities, and on-going construction and development expenses related to the Generation Group's development portfolio.

During the twelve months ended December 31, 2015, the Distribution Group invested $141.4 million (U.S. $107.8 million) in capital expenditures, as compared to $176.8 million (U.S. $155.6 million) during the comparable period in 2014. The Distribution Group's capital expenditures primarily related to reliability enhancements, improvements and replenishment opportunities, and leak prone pipe replacements, leak repairs and pipeline corrosion protection systems relating to safety and reliability at the gas systems.

2016 Capital Investments

The company's consolidated capital investment plan for 2016 is approximately $1,045.0 million, broken down as follows:

(all dollar amounts in $ millions) (U.S. dollar figures translated at the year end exchange rate of $1.3840)
Generation Group development projects, including joint ventures	$	665.0
Generation Group maintenance capital expenditure program	30.0
Distribution Group rate base investments	270.0
Transmission Group development projects	80.0
Total	$	1,045.0

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 2016 capital investments.

Quebec Dam Safety Act

As a result of the dam safety legislation passed in Quebec (Bill C-93), the Generation Group has completed technical assessments on its hydroelectric facility dams owned or leased within the Province of Quebec.  Out of these, nine assessments have been submitted to and accepted by the Quebec government. The assessments have identified possible remedial work at seven facilities. Of these seven, remediation work has now been completed at three facilities, monitoring activities are being performed for two facilities, and remedial work is being planned at two facilities.

The Generation Group currently estimates further capital expenditures of approximately $8.0 million related to compliance with the legislation.  It is anticipated that these expenditures will be invested over a period of several years approximately as follows:

(all dollar amounts in $ millions)	Total		2016	2017	2018	2019
Future Estimated Bill C-93 Capital Expenditures	$	8.0	4.6	2.6	0.5	0.3

The majority of these capital costs are associated with the Belleterre, Rivière-du-Loup, and St. Alban Hydro Facilities.

The Generation Group has been working with the provincial authorities to reclassify, decommission or remove several small dams upstream of the Belleterre Hydro Facility that are not required for power generation. During the first quarter of 2015, four dams were declassified and removed from the CEHQ’s registry, while three others were reclassified to Class E (Very Low Consequence) dams, from higher classes. Upon the recommendation of third party engineers, the Generation Group is in discussion with the relevant government ministries to postpone the decommissioning work on these dams for five years to allow sufficient time to determine the new decommissioning requirements and develop new project plans.

LIQUIDITY AND CAPITAL RESERVES

APUC has revolving credit and letters of credit facilities available for APUC, the Generation Group and the Distribution Group to manage the liquidity and working capital requirements of each division (collectively the “Facilities”).

2015 Annual Report	37
Algonquin Power & Utilities Corp. - Management's Discussion & Analysis

Bank Credit Facilities

The following table sets out the amounts drawn, letters of credit issued and outstanding amounts available to APUC and its operating groups as at December 31, 2015 under the Facilities:

	As at December 31, 2015												As at Dec 31 2014
(all dollar amounts in $ millions)	Corporate			Generation Group			Distribution Group			Total			Total
Committed Facilities	$	65.0		$	441.5		$	276.8		$	783.3		$	647.0
Funds drawn on Facilities	—			(27.3		)	—			(27.3		)	(47.3		)
Letters of Credit issued	(12.9		)	(142.6		)	(8.8		)	(164.3		)	(113.8		)
Liquidity available under the Facilities	$	52.1		$	271.6		$	268.0		$	591.7		485.9
Cash on Hand										124.4			9.3
Total liquidity and capital reserves	$	52.1		$	271.6		$	268.0		$	716.1		$	495.2

On October 30, 2015, the Generation Group entered into a new extendible one year Generation LC Facility. The new facility expands the group's available liquidity by providing for issuances of letters of credit up to a maximum of Cdn. $50 million and U.S. $30 million. Letters of credit in the amount of $80.8 million that were previously issued under the Generation Credit Facility were transferred to the new facility.

As at December 31, 2015, the Company's $65.0 million senior unsecured revolving credit facility (the "Corporate Credit Facility"), was undrawn and had $12.9 million of outstanding letters of credit. Subsequent to year end the maturity of the facility was extended by one year. The facility now matures on November 19, 2017 and is subject to customary covenants.

As at December 31, 2015, the $350.0 million Generation Credit Facility had drawn $27.3 million and had $61.9 million in outstanding letters of credit. The facility matures on July 31, 2019.

As at December 31, 2015, the Distribution Group's $276.8 million (U.S.$200.0 million) senior unsecured revolving credit facility (the "Distribution Credit Facility") had drawn $nil and had $8.8 million (U.S. $6.4 million) of outstanding letters of credit. The facility matures on September 30, 2018 and is subject to customary covenants.

On February 9, 2016, in connection with the acquisition of Empire, the Company obtained a $2.2 billion (U.S. $1.6 billion) in bridge financing commitments from a syndicate of banks. The non-revolving term credit facilities are comprised of a U.S. $1.065 billion debt bridge facility, repayable in full on the first anniversary following its advance, and a U.S. $535.0 million equity bridge facility repayable in full on the first anniversary following its advance. Upon issuing the Debentures (note 25) and receiving the First Instalment, the Company reduced the bridge commitments by $360.0 million (U.S. $263.6 million), as such a total commitment of U.S. $1,336.4 million remains available to the company.

Long Term Debt

On April 30, 2015, the Distribution Group entered into a Note Purchase Agreement for the issuance of U.S. $160.0 million of senior unsecured 30 year notes bearing a coupon of 4.13% via a private placement in the U.S. The proceeds of the financing were used to partially finance the acquisition of the Park Water System and for general corporate purposes. The note was issued in two tranches: U.S. $90.0 million was issued immediately on closing and U.S. $70.0 million was issued on July 15, 2015. The notes have been assigned a rating of BBB High by DBRS. The financing is the fourth series of notes issued pursuant to the company's master indenture.

On October 1, 2015 the Distribution Group repaid the U.S. $9.8 million outstanding under the LPSCo Water System IDA bonds.

On May 12, 2015, the Generation Group repaid, without penalty, U.S. $76.0 million senior project debt of the Shady Oaks Wind Facility.

Subsequent to year end, a subsidiary of the Company entered into a U.S. $235.0 million term credit facility with two U.S. banks. The proceeds of the term credit facility provide the company with additional liquidity for general corporate purposes and acquisitions. The facility matures on July 5, 2017.

As at December 31, 2015, the weighted average tenor of APUC's total long term debt is approximately 9.7 years with an average interest rate of 4.8%.

2015 Annual Report	38
Algonquin Power & Utilities Corp. - Management's Discussion & Analysis

Convertible Unsecured Subordinated Debentures

On February 9, 2016, in connection with the acquisition of Empire, the Company completed the sale of $1.0 billion aggregate principal amount of 5.0% convertible unsecured subordinated debentures. The Debentures will trade on the TSX under the ticker symbol "AQN.IR". The Debentures were sold on an installment basis at a price of $1,000 dollars per Debenture, of which $333 dollars was paid on closing of the Debenture Offering and the remaining $667 dollars (the “Final Installment”) is payable on a date (“Final Installment Date”) to be fixed following satisfaction of conditions precedent to the closing of the acquisition of Empire. On March 9, 2016, the Underwriters exercised their option to acquire an additional $150.0 million of Debentures bringing the total Debentures issued under the Installment Debenture Offering to $1.15 billion.

The Debentures will mature on March 31, 2026 and bear interest at an annual rate of 5% per $1,000 dollars principal amount of Debentures until and including the Final Installment Date, after which the interest rate will be 0%. Based on the first installment of $333 dollars per $1,000 dollars principal amount of Debentures, the effective annual yield to and including the Final Installment Date is 15%, and the effective annual yield thereafter is 0%.

If the Final Installment Date occurs on a day that is prior to the first anniversary of the closing of the Debenture Offering, holders of Debentures who have paid the final installment on or before the Final Installment Date will be entitled to receive, on the business day following the Final Installment Date, in addition to the payment of accrued and unpaid interest to and including the Final Installment Date, an amount equal to the interest that would have accrued from the day following the Final Installment Date to and including the first anniversary of the closing of the Debenture Offering had the Debentures remained outstanding and continued to accrue interest until and including such date (the "Make-Whole Payment"). No Make-Whole Payment will be payable if the Final Installment Date occurs on or after the first anniversary of the closing of the Debenture Offering. Prior to the closing of the Acquisition, the Company will at all times have cash on hand or maintain readily available capacity under the revolving credit facilities of not less than the aggregate amount of the first installment paid on the closing of the Debenture Offering and the exercise of the over-allotment option.

At the option of the holders and provided that payment of the Final Installment has been made, each Debenture will be convertible into common shares of the Company at any time after the Final Installment Date, but prior to the earlier of maturity or redemption by the Company, at a conversion price of $10.60 per common share.

Prior to the Final Installment Date, the Debentures may not be redeemed by the Company, except that Debentures will be redeemed by the Company at a price equal to their principal amount plus accrued and unpaid interest following the earlier of: (i) notification to holders that the conditions necessary to approve the acquisition of Empire will not be satisfied; (ii) termination of the acquisition agreement; and (iii) September 11, 2017 if notice of the Final Installment Date has not been given to holders on or before September 8, 2017. Upon any such redemption, the Company will pay for each Debenture $333 dollars plus accrued and unpaid interest to the holder of the installment receipt. In addition, after the Final Installment Date, any Debentures not converted may be redeemed by the Company at a price equal to their principal amount plus any unpaid interest, which accrued prior to and including the Final Installment Date.

At maturity, the Company will have the right to pay the principal amount due in cash or in common shares. In the case of common shares, such shares will be valued at 95% of their weighted average trading price on the Toronto Stock Exchange for the 20 consecutive trading days ending five trading days preceding the maturity date.

Credit Ratings

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

On February 9, 2016, S&P revised its ratings outlook on APUC and its subsidiaries to negative from stable, while affirming the existing ratings for each of such companies, including the ‘BBB’ long-term corporate rating on APUC. S&P indicated that the negative outlook reflects the execution risk associated with the Empire Acquisition and the potential for lower ratings stemming from the limited ability to absorb weaker financial performance. The revised outlook also reflects S&P’s expectation that certain of the Company's consolidated pro forma credit metrics will materially weaken due to the Debenture Offering (S&P treats the Debentures represented by Instalment Receipts as debt until they are converted into Common Shares).

On February 10, 2016, DBRS Limited (“DBRS”) placed APCo’s and APUC's ‘BBB (low)’ Issuer Ratings and APUC's ‘Pfd-3 (low)’ Preferred Shares ratings ‘Under Review with Developing Implications’. DBRS also placed the ‘BBB (high)’ Issuer Rating, ‘BBB (high)’ Series A, Series C, and Series D Senior Notes ratings of Liberty Utilities Finance GP1, a special purpose financing entity of Liberty Utilities and the ‘BBB (low)’ Senior Unsecured Debentures ratings of APCo ‘Under Review with Developing Implications’. The ratings actions reflect DBRS’s view that the Acquisition will have a relatively neutral impact on the business risk assessments of APUC and its subsidiaries, and that the impact on the financial risk assessment was at the time of the ratings actions uncertain since the financing plan had not been finalized. For APCo, the DBRS announcement states that the credit quality of APCo could be indirectly affected should APUC’s credit profile significantly deteriorate following the Acquisition. This reflects DBRS’s view that APCo relies partly on APUC to provide equity injections to maintain key financial metrics within

2015 Annual Report	39
Algonquin Power & Utilities Corp. - Management's Discussion & Analysis

the rating category and that if APUC’s debt levels increase significantly following the Acquisition, the Company may require more dividends from APCo to service its debt. DBRS indicated that it will review the finalized financing plan and further review any potential impact of the Acquisition on each entity’s credit profile.

Contractual Obligations

Information concerning contractual obligations as of December 31, 2015 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
Long-term debt obligations	$	1,496.1	8.9		222.8		187.6		1,076.8
Advances in aid of construction	$	92.2	1.3		—		—		90.9
Interest on long-term debt obligations	$	664.0	74.3		138.8		117.3		333.6
Purchase obligations	$	243.7	243.7		—		—		—
Environmental obligation	$	78.5	5.4		41.5		1.8		29.8
Derivative financial instruments:
Cross currency swap	$	101.6	4.8		9.0		7.5		80.3
Interest rate swaps	$	9.7	—		9.7		—		—
Currency Forward	$	1.9	1.9		—		—		—
Energy derivative and commodity contracts	$	2.1	1.9		0.2		—		—
Purchased power	$	309.6	82.4		108.2		119.0		—
Gas delivery, service and supply agreements	$	299.7	66.3		83.3		67.6		82.5
Long term service agreements	$	701.4	38.3		73.2		71.7		518.2
Capital projects	$	43.5	35.8		7.6		0.1		—
Operating leases	$	131.8	5.9		10.2		9.5		106.2
Other obligations	$	53.5	12.8		—		—		40.7
Total obligations	$	4,229.3	$	583.7	$	704.5	$	582.1	$	2,359.0

Equity

The common shares of APUC are publicly traded on the Toronto Stock Exchange (“TSX”).  As at December 31, 2015, APUC had 255,869,419 issued and outstanding common shares.

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

On February 9, 2016, the Company completed the sale of $1.0 billion aggregate principal amount of 5.0% convertible unsecured subordinated debentures (the “Debentures”). On March 9, 2016 the Underwriters exercised the option to purchase an additional $150.0 million of Debentures bringing the total Debentures sold by APUC to $1.15 billion.

At the option of the holders, each Debenture will be convertible into common shares of the Company at any time after the Company acquires Empire, at a conversion price of $10.60 per common share.

On December 2, 2015, APUC completed the offering of 14,355,000 common shares at a price of $10.45 per share, for gross proceeds of approximately $150.0 million.

APUC is also authorized to issue an unlimited number of preferred shares, issuable in one or more series, containing terms and conditions as approved by the Board.  As at December 31, 2015, APUC had outstanding:

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

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

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

2015 Annual Report	40
Algonquin Power & Utilities Corp. - Management's Discussion & Analysis

APUC has a shareholder dividend reinvestment plan (the “Reinvestment Plan”) for registered holders of shares of APUC. As at December 31, 2015, 24.0 million common shares representing approximately 9% of total shares outstanding had been registered with the Reinvestment Plan and 3,230,697 shares were issued during the year ended December 31, 2015. During the quarter ended December 31, 2015, 997,532 common shares were issued under the Reinvestment Plan, and subsequent to the end of the quarter, on January 15, 2015, an additional 292,337 common shares were issued under the Reinvestment Plan.

Emera shareholdings and subscription receipts

On October 7, 2014, the Company issued 8,708,170 Subscription Receipts of APUC at a purchase price of $8.90 per Subscription Receipt for an aggregate subscription price of $77.5 million. The investment was made under the Strategic Investment Agreement between Emera and APUC, in support of the acquisition by APUC of the Odell Wind Project in Minnesota (the “Odell Acquisition”). As at November 14, 2015 (the first anniversary of the closing of the Odell Acquisition), the Subscription Receipts were convertible to common shares of APUC on a one-for-one basis, subject to adjustments as provided in the applicable subscription agreement.  On October 7, 2016, the Subscription Receipts will automatically convert into common shares of APUC, if Emera has not yet exercised its option to convert.

On December 29, 2014, the Corporation issued 3,316,583 subscription receipts of APUC at a purchase price of $9.95 per subscription receipt for an aggregate subscription price of $33.0 million. The investment was made under the Strategic Investment Agreement between Emera and APUC, in support of the acquisition by APUC of the Park Water System in Montana and California (the “Park Water Acquisition”). The proceeds of the subscription have been used by APUC to partially finance the Park Water Acquisition. As at December 29, 2015 (the first anniversary of the closing of the subscription transaction), the Subscription Receipts were convertible to common shares of APUC on a one-for-one basis, subject to adjustments as provided in the applicable subscription agreement.  On December 29, 2016, the Subscription Receipts will automatically convert into common shares of APUC, if Emera has not yet exercised its option to convert.

Conversion of the aforementioned Subscription Receipts into common shares is conditional on Emera’s holdings not exceeding 25% of the outstanding common shares of APUC at the time of conversion.

As at March 10, 2016, in total, Emera owns 50,126,766 APUC common shares representing approximately 19.6% of the total outstanding common shares of the Company, and there are 12,024,753 subscription receipts currently held by Emera. APUC believes the issuance of shares to Emera is an efficient way to raise equity as it avoids underwriting fees, legal expenses and other costs associated with raising equity in the capital markets.

SHARE BASED COMPENSATION PLANS

For the three and twelve months ended December 31, 2015, APUC recorded $1.7 million and $5.3 million, respectively, in total share-based compensation expense, as compared to $1.1 million and $3.2 million, respectively, for the same period in 2014.  No tax deduction was realized in the current year. The compensation expense is recorded as part of administrative expenses in the audited Consolidated Statement of Operations. The portion of share-based compensation costs capitalized as cost of construction is insignificant.

As at December 31, 2015, total unrecognized compensation costs related to non-vested options and share unit awards were $3.1 million and $1.9 million, respectively, and are expected to be recognized over a period of 1.74 and 1.63 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 year, the Company issued 1,627,525 options to employees of the Company.

As at December 31, 2015, a total of 7,164,652 options are issued and outstanding under the plan.

Performance Share Units

APUC issues performance share units (“PSUs”) to certain members of management other than senior executives as part of APUC’s long-term incentive program.  The PSUs provide for settlement in cash or shares at the election of APUC.

2015 Annual Report	41
Algonquin Power & Utilities Corp. - Management's Discussion & Analysis

During the year, the Company settled 41,131 vested PSUs. The plan provides for settlement in cash or shares at the election of the Company. At the annual general meeting held on June 18, 2014, the shareholders approved a maximum of 500,000 shares issuable from Treasury to settle PSUs. With the ability to issue shares from Treasury or purchase shares on the market, the Company expects to settle the remaining PSUs in shares. As a result, the PSUs continue to be accounted for as equity awards. During the year, the Company issued 212,250 PSUs to executives and employees of the Company.

As at December 31, 2015, a total of 564,116 PSU's are granted and outstanding under the PSU plan.

Directors Deferred Share Units

APUC has a Deferred Share Unit Plan.  Under the plan, non-employee directors of APUC may elect annually to receive all or any portion of their compensation in deferred share units (“DSUs”) in lieu of cash compensation.  The DSUs provide for settlement in cash or shares at the election of APUC.  As APUC does not expect to settle the DSU’s in cash, these DSUs are accounted for as equity awards. During the year, the Company issued 47,230 DSUs to the directors of the Company.

As at December 31, 2015, a total of 157,471 DSUs had been granted under the DSU plan.

Employee Share Purchase Plan

APUC has an Employee Share Purchase Plan (the “ESPP”) which allows eligible employees to use a portion of their earnings to purchase common shares of APUC. The aggregate number of shares reserved for issuance from treasury by APUC under this plan shall not exceed 2,000,000 shares. During the year, the Company issued 111,355 common shares to employees under the ESPP plan.

As at December 31, 2015, a total of 351,766 shares had been issued under the ESPP.

MANAGEMENT OF CAPITAL STRUCTURE

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

APUC’s objectives when managing capital are:

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

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

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

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

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

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

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

RELATED PARTY TRANSACTIONS

Emera Inc

A member of the Board of Directors of APUC is an executive at Emera. During 2015, the Energy Services Business sold electricity to Maine Public Service Company (“MPS”), and Bangor Hydro ("BH") subsidiaries of Emera, amounting to U.S.$6.7 million (2014 - U.S. $9.8 million). During 2015, Liberty Utilities purchased natural gas amounting to U.S. $2.3 million (2014 - U.S. $4.0 million) 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.

There was U.S. $0.5 million included in accruals in 2015 (2014 - $nil) related to these transactions at the end of the periods.

Equity-method investments

2015 Annual Report	42
Algonquin Power & Utilities Corp. - Management's Discussion & Analysis

The Company provides administrative services to its equity-method investees and is reimbursed for incurred costs. To that effect, the Company charged its equity-method investees $2.0 million (2014 - $0.2 million) during the year.

Senior Executives

As at December 31, 2015, $nil (December 31, 2014 - $0.05 million) was due from Algonquin Power Systems Ltd., a corporation partially owned by Ian Robertson and Chris Jarratt (collectively "Senior Executives").

Chartered Aircraft

As part of its normal business practice, APUC has utilized chartered aircraft when it is beneficial to do so and had previously entered into a block time agreement to charter aircraft in which Senior Executives have a partial ownership.

The Company terminated the agreement effective June 28, 2015 and paid a usage shortfall fee of $0.01 million. During the year ended December 31, 2015, APUC reimbursed direct costs in connection with the use of the aircraft prior to termination of the block time agreement of $0.5 million (2014 - $0.7 million).

Office Facilities

Until the fourth quarter of 2014 APUC had leased its head office facilities from an entity partially owned by Senior Executives. During the fourth quarter of 2014, APUC terminated the related party lease and moved all head office employees into new premises owned by the Company. Base lease costs for the year ended December 31, 2015 were $nil (2014 - $0.4 million).

Other

A spouse of one of the Senior Executives was employed to provide market research services to certain subsidiaries of the Company. During the year ended December 31, 2015 APUC paid $0.022 million (2014 - $0.2 million) in relation to these services. The spouse is no longer employed by the Company.

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 18MW Long Sault Hydro Facility. A final post-closing adjustment related to the transaction is expected to be settled in 2016.

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. APUC’s ERM policy details the risk management processes, risk appetite, and risk governance structure which clearly establishes accountabilities for managing risk across the organization. In 2015, the Risk and Insurance Management Society (RIMS) recognized APUC's enterprise risk management program for achieving sustainable and repeatable ERM practices.

As part of the risk management processes, risk registers have been developed across the organization through ongoing risk identification and risk assessment exercises facilitated by APUC’s internal ERM team. Key risks and associated mitigation strategies are reviewed by the Executive Risk Steering Committee on a monthly basis and presented to the Board of Directors on a quarterly basis. The key risk categories assessed include: safety, environment, natural disasters, security (physical and cyber), operations, organizational effectiveness, contracts, budget, capital projects, return on M&A activity, markets, liquidity, financial reporting, strategic, and regulatory.

Risks are assessed consistently across the organization using a common risk matrix to assess impact and likelihood. Financial, reputation and safety implications are considered when determining the impact of a potential risk. Risk treatment priorities are established based upon these risk assessments and incorporated into the development of APUC’s strategic plans.

The development and execution of risk treatment plans are actively monitored by the ERM team through a centralized risk register software application. APUC’s internal audit team is responsible for conducting audits to validate and test the effectiveness of controls for the key risks. Audit findings are discussed with business owners and reported to the Board audit committee on a quarterly basis. All material changes to exposures, controls or treatment plans of key risks are reported to the ERM team, Executive Risk Steering Committee, and the Board of Directors for consideration.

APUC’s ERM framework follows the guidance of ISO 31000;2009. The Board oversees management to ensure the risk governance structure and risk management processes are robust, and that APUC’s risk appetite is thoroughly considered in decision-making across the organization.

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.

2015 Annual Report	43
Algonquin Power & Utilities Corp. - Management's Discussion & Analysis

Treasury Risk Management

Foreign Currency Risk

Currency fluctuations may affect the cash flows APUC would realize from its consolidated operations, as certain APUC subsidiary businesses sell electricity or provide utility services in the United States and receive proceeds from such sales in U.S. dollars. Such APUC businesses also incur costs in U.S. dollars. At the current exchange rate, approximately 81% of EBITDA in 2015 and 80% of cash flow from operations is generated in U.S. dollars. APUC estimates that, on an unhedged basis, a $0.10 increase in the strength of the U.S. dollar relative to the Canadian dollar would result in a net impact on U.S. operations of approximately $30.6 million ($0.12 per share) on an annual basis.

In light of the currency profile of its operations, APUC pays its dividend in U.S. dollars. APUC further manages currency risk through the matching of U.S. long term debt to finance its U.S. operations, thereby creating a natural hedge for the operating profit vis a vis financing cost. APUC’s policy is not to utilize derivative financial instruments for trading or speculative purposes. APUC may from time to time enter into short term foreign currency derivative contracts to hedge exposure of anticipated transactions denominated in a foreign currency.

The cash consideration for the Acquisition of Empire is required to be paid in U.S. dollars, while the Debenture Offering which represents a significant portion of the funds ultimately used to finance the Acquisition, are denominated in Canadian dollars. As a result, increases in the value of the U.S. dollar versus the Canadian dollar prior to payment of the final installment on the Debenture Offering will increase the purchase price translated in Canadian dollars and thereby reduce the proportion of the purchase price for the Acquisition ultimately obtained by APUC under the Debenture Offering, which could cause a failure to realize the anticipated benefits of the Acquisition. To mitigate this risk, the Company has converted the initial amounts received from the Debenture Offering into U.S. dollars. The Company is evaluating the merits of entering into future hedging agreements to mitigate the risk on all or a portion of the remaining funds to be received. Should the Acquisition not close and the Company is required to repay the initial installment received on the Debentures it will have to translate the funds on the initial installment receipt translated into U.S. dollars back to Canadian Dollars.

Market Price Risk

The Distribution Business Group is not exposed to market price risk as rates charged to customers are stipulated by the respective regulatory bodies.

The Generation 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 Generation 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 Generation Group generally seeks to structure hedges to cover less than 100% of the anticipated production, thereby

2015 Annual Report	44
Algonquin Power & Utilities Corp. - Management's Discussion & Analysis

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 Generation 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 group along with residual exposures to the market are detailed below:

On May 15, 2012, the Generation Group entered into a financial hedge, which expires December 31, 2016, with respect to its Dickson Dam Hydro Facility located in the Western region. The financial hedge is structured to hedge 75% of the facility's expected production volume against exposure to the Alberta Power Pool’s current spot market rates. The annual unhedged production based on long term projected averages is approximately 16,000 MW-hrs annually. Therefore, each U.S. $10.00 per MW-hr change in the market prices in the Western region would result in a change in revenue of U.S. $0.2 million on an annualized basis.

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

The December 10, 2012 acquisition of Senate Wind Facility included a physical hedge, which commenced on January 1, 2013 for a 15 year period. The physical hedge is structured to hedge 64% of the Senate Wind Facility’s expected production volume against exposure to ERCOT North Zone current spot market rates.  The annual unhedged production based on long term projected averages is approximately 188,000 MW-hrs annually. Therefore, each U.S. $10 per MW-hr change in the market prices would result in a change in revenue of about U.S. $1.9 million for the year.

The December 10, 2012 acquisition of the Minonk Wind Facility included a financial hedge, which commenced on January 1, 2013 for a 10 year period. The financial hedge is structured to hedge 73% of the Minonk Wind Facility’s expected production volume against exposure to PJM Northern Illinois Hub current spot market rates. The annual unhedged production based on long term projected averages is approximately 186,000 MW-hrs annually. Therefore, each U.S. $10 per MW-hr change in market prices would result in a change in revenue of about U.S. $1.9 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 Generation Group enters into short-term derivative contracts (with terms of one to three months) to further mitigate market price risk exposure due to production variability. As at December 31, 2015, the Generation Group had entered into hedges with a cumulative notional quantity of 10,480 MW-hrs.

The January 1, 2013 acquisition of the Shady Oaks Wind Facility included a power sales contract, which commenced on January 1, 2013 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 about U.S. $0.5 million for the year.

Credit/Counterparty Risk

APUC and its subsidiaries are subject to credit risk through its long term power purchase contracts, trade receivables, derivative financial instruments and short term investments. APUC has processes in place to monitor and evaluate this risk on an ongoing basis including background credit checks and security deposits from new customers.

APUC does not believe the credit risk of default by counterparties to its long term power purchase contracts to be significant, as approximately 83.9% of the Generation Group's revenues are earned from large utility customers having a credit rating of Baa1 or better by Moody's Rating Services or BBB+ or higher by S&P Rating Services. The following chart sets out the Generation Group’s significant customers, their credit ratings and percentage of total revenue associated with the customer:

2015 Annual Report	45
Algonquin Power & Utilities Corp. - Management's Discussion & Analysis

Counterparty	Credit Rating 1	Approximate Annual Revenues		Percent of Revenue
Generation Group - Renewable Energy
PJM Interconnection LLC	Aa3	$	40.5	18.2	%
Manitoba Hydro	Aa1	29.4		13.2	%
Hydro Quebec	Aa2	27.6		12.4	%
Pacific Gas and Electric Company	BBB	21.7		9.7	%
Ontario Electricity Financial Corporation	Aa2	19.3		8.7	%
US Wind Hedge Counterparty	A3	17.9		8.0	%
Connecticut Light and Power	Baa1	16.7		7.5	%
Commonwealth Edison	Baa1	13.5		6.1	%
Total – Generation Group		$	186.6	83.8	%

1 Ratings by Moody’s or Standard & Poor’s

The remaining revenue of the company is primarily earned by the Distribution Group. In this regard, the credit risk attributed to the Distribution Group's accounts receivable balances at the water and wastewater distribution systems total U.S. $4.6 million which is spread over approximately 104,000 connections, resulting in an average outstanding balance of approximately $40 dollars per connection.

The natural gas distribution systems accounts receivable balances related to the natural gas utilities total U.S. $53.8 million, while electric distribution systems accounts receivable balances related to the electric utilities total U.S. $26.9 million. The natural gas and electrical utilities, respectively, derive over 90% and 87% of their revenue from residential customers.

In addition to the counterparty risk related to customer sales outlined above, the Generation and Distribution Groups utilize derivative instruments as hedges of certain financial risks as discussed elsewhere in this MD&A. APUC is exposed to credit risk related to counterparties to the extent those derivative instruments are in an asset position at a point in time. The company manages counterparty risk by entering into these instruments with counterparties having a credit rating of BBB- or better.

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 Credit Facility is subject to a variable interest rate and had no amounts outstanding as at December 31, 2015. As a result, a 100 basis point change in the variable rate charged would not impact interest expense.

• The Generation Credit Facility is subject to a variable interest rate and had $27.3 million outstanding as at December 31, 2015. As a result, a 100 basis point change in the variable rate charged would impact interest expense by $0.3 million annually.

• The Distribution Credit Facility is subject to a variable interest rate and had no amounts outstanding as at December 31, 2015. As a result, a 100 basis point change in the variable rate charged would not impact interest expense.

• To mitigate financing risk, from time to time APUC may seek to fix interest rates on expected future financings. In the fourth quarter of 2014, the Generation Group entered into a hedge to fix the underlying interest rate for the anticipated refinancing of its $135.0 million bond maturing in July 2018. Hedge accounting treatment applies to this transaction. Consequently, changes in fair value, to the extent deemed effective, are being recorded into Other Comprehensive Income.

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.

Tax Risk and Uncertainty

Although APUC is of the view that all expenses being claimed by APUC are reasonable and that the cost amount of APUC’s depreciable properties have been correctly determined, there can be no assurance that the Canada Revenue Agency ('CRA")or the Internal Revenue Service will agree. A successful challenge by either agency regarding the deductibility of such expenses or the correctness of such cost amounts could impact the return to shareholders.

Unit Exchange Transaction

2015 Annual Report	46
Algonquin Power & Utilities Corp. - Management's Discussion & Analysis

On October 27, 2009, unitholders of Algonquin Power Income Fund exchanged their trust units on a one for one basis for common shares of Algonquin Power & Utilities Corp (the “Unit Exchange Transaction”). As a result of the Unit Exchange Transaction, APUC recorded certain additional tax attributes to the extent management believed they were more likely than not to be realized. The excess of the carrying amount of the tax attributes assumed over the consideration paid was recorded as a deferred credit of $55.6 million on the date of the Unit Exchange Transaction (the “Transaction Date”). The deferred credit has been recognized into income as a deferred income tax recovery in relative proportion to the amount of the related tax attributes that have been utilized since the Transaction Date.

Earlier in the year APUC received correspondence from the CRA which outlined its intention to challenge the tax consequences of the Unit Exchange Transaction. The CRA was seeking to apply the acquisition of control rules through application of the general anti-avoidance rule of the Income Tax Act (Canada), the effect of which would be to deny APUC the benefit of the tax attributes it assumed as part of the Unit Exchange Transaction.

On June 26, 2015, APUC entered into an agreement with CRA regarding a CRA proposal to reassess APUC's 2009 through 2013 income tax filings in relation to the Unit Exchange Transaction. The agreement resulted in a $16.0 million reduction in APUC's deferred tax assets and a proportional reduction of $13.3 million in deferred credits. Consequently, APUC's results for 2015 reflect a $2.7 million net non-cash charge to deferred income tax expense.

Liquidity Risk

Liquidity risk is the risk that APUC and its subsidiaries will not be able to meet their financial obligations as they become due.

Both the Generation Group and the Distribution Group have established financing platforms to access new liquidity from the capital markets as requirements arise. APUC continually monitors the maturity profile of its debt and adjusts accordingly to ensure sufficient liquidity exists to meet liabilities when due.

As at December 31, 2015, APUC and its subsidiaries had a combined $591.7 million of liquidity available under the Facilities remaining and $124.4 million of cash resulting in $716.1 million of total liquidity and capital reserves.

APUC currently pays a dividend of U.S. $0.3850 per common share per year. The Board determines the amount of dividends to be paid, consistent with APUC’s commitment to the stability and sustainability of future dividends, after providing for amounts required to administer and operate APUC and its subsidiaries, for capital expenditures in growth and development opportunities, to meet current tax requirements, and to fund working capital that, in its judgment, ensures APUC’s long-term success. Based on the level of common share dividends paid during the year ended December 31, 2015, cash provided by operating activities exceeded common share dividends declared by 2.0 times and Adjusted Cash From Operations exceeds common share dividends by 2.2 times.

The current and long term portion of debt totals approximately $1,496.1 million with maturities set out in the Contractual Obligation table. In the event that APUC was required to replace the Facilities and project debt with borrowings having less favorable terms or higher interest rates, the level of cash generated for dividends and reinvestment may be negatively impacted.

The cash flow generated from several of APUC’s operating facilities is subordinated to senior project debt. In the event that there was a breach of covenants or obligations with regard to any of these particular loans which was not remedied, the loan could go into default which could result in the lender realizing on its security and APUC losing its investment in such operating facility. APUC actively manages cash availability at its operating facilities to ensure they are adequately funded and minimize the risk of this possibility.

Downgrade in the Company's Credit Rating Risk

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

The ratings indicate the agencies’ assessment of APUC's ability to pay the interest and principal of debt securities it issues. A rating is not a recommendation to purchase, sell or hold securities and each rating should be evaluated independently of any other rating. The lower the rating, the higher the interest cost of the securities when they are sold. A downgrade in APUC’s or its subsidiaries issuer corporate credit ratings would result in an increase in APUC’s borrowing costs under its bank credit facilities and future long term debt securities issued. If any of APUC’s ratings fall below investment grade (investment grade is defined as BBB- or above for S&P and BBB low or above for DBRS), APUC’s ability to issue short-term debt, or other securities or to market those securities would be impaired or made more difficult or expensive. Therefore, any such downgrades could have a material adverse effect on APUC’s business, cost of capital, financial condition and results of operations.

APUC mitigates this risk by actively monitoring and targeting the key credit metrics and other considerations used by the rating agencies to evaluate its ratings. No assurances can be provided that any of APUC's current ratings will remain in effect for any given period of time or that a rating will not be lowered or withdrawn entirely by a rating agency if, in its judgment, circumstances in the future so warrant.

2015 Annual Report	47
Algonquin Power & Utilities Corp. - Management's Discussion & Analysis

Commodity Price Risk

The Generation Group’s exposure to commodity prices is primarily limited to exposure to natural gas price risk. The Distribution Groups is exposed to energy and natural gas price risks at its electric and natural gas systems. In this regard, a discussion of this risk is set out as follows:

• The Sanger Thermal Facility’s PPA includes provisions which reduce its exposure to natural gas price risk. In this regard, a $1.00 increase in the price of natural gas per MMBTU, based on expected production levels, would result in an increase in net revenue by approximately $0.2 million on an annual basis.

• The Windsor Locks Thermal Facility’s Energy Services Agreement includes provisions which reduce its exposure to natural gas price risk but has exposure to market rate conditions for sales above those to its primary customer. In this regard, a $1.00 increase in the price of natural gas per MMBTU, based on expected production levels, would result in a decrease in net revenue by approximately $0.1 million on an annual basis.

• The Maritime region provides short-term energy requirements to various customers at fixed rates. The energy requirements of these customers are estimated at approximately 164,000 MW-hrs in fiscal 2016, of which 141,000 MW-hrs is presently contracted. While the Tinker Hydro Facility is expected to provide the majority of the energy required to service these customers, the Maritime region anticipates having to purchase approximately 23,000 MW-hrs of its energy requirements at the ISO-NE spot rates to supplement self-generated energy should the Maritime region be able to reach the estimated 164,000 MW-hrs. The risk associated with the expected market purchases of 23,000 MW-hrs is mitigated through the use of short-term financial energy hedge contracts which cover approximately 73% of the Maritime region's anticipated purchases during the price-volatile winter months at an average rate of approximately $79 per MW-hr. For the amount of anticipated purchases not covered by hedge contracts, each $10.00 change per MW-hr in the market prices in ISO-NE would result in a change in expense of $0.1 million on an annualized basis.

The CalPeco Electric System provides electric service to the Lake Tahoe California basin and surrounding areas at rates approved by the CPUC. The CalPeco Electric System purchases the energy, capacity, and related service requirements for its customers from NV Energy via a PPA at rates reflecting NV Energy’s system average costs.

The CalPeco Electric System's tariffs allow for the pass-through of energy costs to its rate payers on a dollar for dollar basis, through the energy cost adjustment clause (“ECAC”) mechanism, which allows for the recovery or refund of changes in energy costs that are caused by the fluctuations in the price of fuel and purchased power. On a monthly basis, energy costs are compared to the CPUC approved base tariff energy rates and the difference is deferred to a balancing account. Annually, based on the balance of the ECAC balancing account, if the ECAC revenues were to increase or decrease by more than 5%, the CalPeco Electric System's ECAC tariff allows for a potential adjustment to the ECAC rates which would eliminate the risk associated with the fluctuating cost of fuel and purchased power. The CalPeco Electric System also benefits from a revenue decoupling mechanism and a vegetation management memorandum account. The revenue decoupling mechanism decouples base revenues from fluctuations caused by weather and economic factors reducing volumetric risk for the utility. The vegetation management memorandum account allows for the tracking and pass through of vegetation management expenses, one of the largest expenses of the utility, reducing the potential for expenses to exceed the amounts allowed for in general rates.

The Granite State Electric System is an open access electric utility allowing for its customers to procure commodity services from competitive energy suppliers. For those customers that do not choose their own competitive energy supplier, Granite State Electric System provides a Default Service offering to each class of customers through a competitive bidding process. This process is undertaken semi-annually for all customers. The winning bidder is obligated to provide a full requirements service based on the actual needs of the Granite State Electric System’s Default Service customers. Since this is a full requirements service, the winning bidder(s) take on the risk associated with fluctuating customer usage and commodity prices. The supplier is paid for the commodity by the Granite State Electric System which in turns receives pass-through rate recovery through a formal filing and approval process with the NHPUC on a semi-annual basis. The Granite State Electric System is only committed to the winning Default Service supplier(s) after approval by the NHPUC so that there is no risk of commodity commitment without pass-through rate recovery.

The EnergyNorth Natural Gas System purchases pipeline capacity, storage and commodity from a variety of counterparties. The EnergyNorth Natural Gas System's portfolio of assets and its planning and forecasting methodology are approved by the NHPUC bi-annually through Least Cost Integrated Resource Plan filing. In addition, EnergyNorth Natural Gas System files with the NHPUC for recovery of its transportation and commodity costs on a semi-annual basis through the Cost of Gas ("COG") filing and approval process. The EnergyNorth Natural Gas System establishes rates for its customers based on the NHPUC approval of its filed COG. These rates are designed to fully recover its anticipated transportation and commodity costs. In order to minimize commodity price fluctuations, the EnergyNorth Natural Gas System locks in a fixed price basis for approximately 14% of its normal winter period purchases under a NHPUC approved hedging program. All costs associated with the fixed basis hedging program are allowed to be pass-through to customers through the COG filing and the approved rates in said filing. Should commodity prices increase or decrease relative to the initial semi-annual COG rate filing, the EnergyNorth Natural Gas System has the right to automatically adjust its rates going forward in order to minimize any under

2015 Annual Report	48
Algonquin Power & Utilities Corp. - Management's Discussion & Analysis

or over collection of its gas costs. In addition, any under collections may be carried forward with interest to the next year’s corresponding COG filing, i.e. winter to winter and summer to summer.

The Midstates Gas Systems purchases pipeline capacity, storage and commodity from a variety of counterparties, and files with the three individual State Commissions for recovery of its transportation and commodity costs through an annual Purchase Gas Adjustment (“PGA”) filing and approval process. The Midstates Gas Systems establishes rates for its customers within the PGA filing and these rates are designed to fully recover its anticipated transportation and commodity costs. In order to minimize commodity price fluctuations, the Company has implemented a commodity hedging program designed to hedge approximately 25-50% of its non-storage related commodity purchases. All gains and losses associated with the hedging program are allowed to be pass-through to customers through the PGA filing and are embedded in the approved rates in said filing. Rates can be adjusted on a monthly or quarterly basis in order to account for any commodity price increase or decrease relative to the initial PGA rate, minimizing any under or over collection of its gas costs.

The Georgia (Peach State) Gas System purchases pipeline capacity, storage and commodity from a variety of counterparties, and files with the Georgia PSC for recovery of its transportation, storage and commodity costs through a monthly PGA filing process.  The Peach State Gas System establishes rates for its customers within the PGA filings and these rates are designed to fully recover its anticipated transportation, storage and commodity costs.  In order to minimize commodity price fluctuations, the annual Gas Supply Plan filed by the Company and approved by the PSC includes a commodity hedging program designed to hedge approximately 30% of its non-storage related commodity purchases during the winter months.  All gains and losses associated with the hedging program are passed through to customers in the PGA filings and are embedded in the approved rates in such filings.  Rates can be adjusted on a monthly basis in order to account for any differences in gas costs relative to the amounts assumed in the PGA filings, minimizing any under or over collection of its gas costs.

OPERATIONAL RISK MANAGEMENT

Mechanical and Operational Risks

APUC's profitability could be impacted by, among other things, equipment failure, the failure of a major customer to fulfill its contractual obligations under its PPA, reductions in average energy prices, a strike or lock-out at a facility, and expenses related to claims or clean-up to adhere to environmental and safety standards.

The Generation Group's hydro assets utilize dams to pond water for generation and if the dams burst potentially catastrophic amounts of water would flood downriver from the facility. The dams can be subjected to drought conditions and lose the ability to generate during peak load conditions, causing the facilities to fall short of either hedged or PPA committed production levels. The risks of the hydro facilities are mitigated by regular dam inspections and a maintenance program of the facility to lessen the risk of dam failure.

The Generation Group's wind assets could catch on fire and, depending on the season, could ignite significant amounts of forest or crop downwind from the wind farms. The wind units could also be affected by large atmospheric conditions (e.g. El Nina), which will lower wind levels below our PPA and hedge minimum production levels. Production risks associated with the wind turbine generators is mitigated by properly maintaining the units using long term maintenance agreements with the turbine O&M’s, which provide for regular inspections and maintenance of property and liability insurance policies. Icing can be mitigated by shutting down the unit as icing is detected at the site.

The Generation Group's Thermal Energy Division uses natural gas and oil, and produce exhaust gases, which if not properly treated and monitored could cause hazardous chemicals to be released into the atmosphere.  The units could also be restricted from purchasing gas/oil due to either shortages or pollution levels, which could hamper output of the facility. The mechanical and operational risks at the Thermal Energy Division are mitigated through the regular maintenance of the boiler system, and by continual monitoring of exhaust gases. Fuel restrictions can be hedged somewhat by long term purchases.

All of the Generation Group's electric generating stations are subject to mechanical breakdown. The risk of mechanical breakdown is mitigated by properly maintaining the units and by regular inspections.

The Distribution Group's water and wastewater distribution systems operate under pressurized conditions within pressure ranges approved by regulators.  Should a water distribution network become compromised or damaged, the resulting release of pressure could result in serious injury or death to individuals or damage to other property.

The Distribution Group's electric distribution systems are subject to storm events, usually winter storm events, whereby power lines can be brought down with the attendant risk to individuals and property. In addition, in forested areas, power lines brought down by wind can ignite forest fires which also bring attendant risk to individuals and property.

The Distribution Group's natural gas distribution systems are subject to risks which may lead to fire and/or explosion which may impact life and property. Risks include third party damage, compromised system integrity, type/age of pipelines, and severe weather events.

2015 Annual Report	49
Algonquin Power & Utilities Corp. - Management's Discussion & Analysis

These risks are mitigated through the diversification of APUC’s operations, both operationally (the Generation and Distribution Groups) and geographically (Canada and U.S.), the use of regular maintenance programs, including pipeline safety programs and compliance programs, and maintaining adequate insurance and the establishment of reserves for expenses.

Regulatory Risk

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

The Distribution Group’s facilities are subject to rate setting by state regulatory agencies. The time between the incurrence of costs and the granting of the rates to recover those costs by state regulatory agencies is known as regulatory lag. As a result of regulatory lag, inflationary effects may impact the ability to recover expenses, and profitability could be impacted. As a strategy to mitigate, the Distribution Group seeks to obtain approval for regulatory constructs in the states in which it operates to allow for timely recovery of operating expense. A fundamental risk faced by any regulated utility is the disallowance of costs to be placed into its revenue requirement by the utility's regulator. To the extent proposed costs are not allowed into rates, the utility will be required to find other efficiencies or cost savings to achieve its allowed returns.

The Distribution Group regularly works with its governing authorities to manage the affairs of the business employing both local state level and corporate resources.

Condemnation Expropriation Proceedings

The Distribution Group's distribution systems could be subject to condemnation or other methods of taking by government entities under certain conditions. Any taking by government entities would legally require just and fair compensation be paid to the Distribution Group and the Distribution Group believes such compensation would reflect fair market value for any assets that are taken. Determination of such fair and just compensation is undertaken pursuant to a legal proceeding and, therefore, there is no assurance that the value received for assets taken will be in excess of book value. In 2014, the Company entered into an agreement to acquire Western Water Holdings LLC, which is the parent company of the regulated water distribution utility Park Water Company.  The Park Water Company owns and operates three regulated water utilities engaged in the production, treatment, storage, distribution, and sale of water in Southern California and Western Montana.  Mountain Water Company is the water utility in Western Montana serving the municipality of Missoula owned by Park Water Company.

Mountain Water Company is currently the subject of a condemnation proceeding by the city of Missoula. It is not known when the condemnation proceeding will conclude or whether the city of Missoula will ultimately take possession of Mountain Water. The City’s right to take Mountain Water is currently on appeal before the Montana Supreme Court, which is set to hear the appeal on April 22, 2016. If the City of Missoula prevails on appeal and ultimately takes possession of Mountain Water, 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) plus accrued interest and attorney's fees as determined by the Montana court. Mountain Water is seeking U.S. $4.8 million in attorney's fees and U.S. $16.0 million in interest. The City of Missoula opposes an award of attorney's fees and interests as requested by Mountain Water. On December 22, 2015, various developers filed a Petition for Declaratory and Other Relief in Missoula County District Court against Mountain Water and the City of Missoula. The lawsuit pertains to Funded By Others (“FBO”) contracts between each developer and Mountain Water. Under those FBO contracts, the developers paid for facilities to provide water service. Mountain Water agreed to refund those developer advances under the FBO contracts over a 40 year period. These FBO contracts represent a liability of U.S. $22.0 million on the balance sheet of Mountain Water. While there is no allegation of breach by Mountain Water under the FBO contracts, the developers are seeking to enforce these refunds should the utility be transferred to the city. That lawsuit is ongoing and is in the early stages of litigation. In addition, the Montana Public Service Commission (“Montana PSC”) has asserted that the indirect change of control of Mountain Water required its approval and is, therefore, investigating potential changes to the rates of Mountain Water. Montana PSC has also expressed an intention to seek penalties against Mountain Water. The Montana PSC has acknowledged that it has no express authority over the acquisition transaction under statute, but has asserted that such authority should be implied. These matters are in the early stages.

On January 8, 2016, the Town of Apple Valley filed an eminent domain complaint against Apple Valley. In California, parties to a condemnation case typically agree for the case to be bifurcated into two phases. The first phase will determine the necessity of the taking. The second phase will involve the valuation of the utility assets. If the Town of Apple Valley is successful in the right to take proceeding, a second phase will be held to determine the fair market value of Apple Valley. At present, a trial setting conference has been set for July 7, 2016. The matter is expected to take two to three years to resolve. The condemnation action has potential financial implications for Liberty Utilities depending on the outcome of the condemnation process. In the event that the Town of Apple Valley prevails in the necessity phase of the condemnation case, the financial impact of the condemnation case will depend on the ultimate determination of the fair market value of Apple Valley’s assets by a jury if so elected by either party, along with a determination of interest and attorney’s fees by the court.

Acquisition Risk

The risks associated with the Company's acquisition strategy include potential difficulties inherent in acquisitions that may adversely affect the results of an acquisition and these include delays in implementation or unexpected costs or liabilities, as well as the risk of failing to realize operating benefits or synergies from completed transactions. The Company mitigates these risks by following systematic procedures for integrating acquisitions, applying strict financial metrics to any potential acquisition and subjecting the process to close monitoring and review by the Board of Directors.

Completion of the Acquisition of Empire

The Acquisition of Empire is subject to risks that the Acquisition will not close on the terms negotiated (including with respect to the consideration to be paid for the common stock of Empire) or at all, that adverse terms or conditions could be imposed on the Company or Empire in connection with obtaining approvals required to complete the Acquisition, and that completing the Acquisition may not have the expected benefits or may otherwise adversely affect the Company.

The completion of the Acquisition is subject to satisfaction or, in certain cases, waiver of certain conditions. These conditions include approval by the shareholders of Empire, the expiration or termination of the applicable waiting period under the Hart Scott Rodino Act, obtaining clearance from the Committee on Foreign Investment in the United States, and obtaining the approval of each of FERC, the FCC and the State Commissions. In the event that any such regulatory agencies impose unfavourable terms or conditions on the Company or Empire (including requirements to sell assets or limitations on the future conduct of the combined entities), the Company could still be required to complete the transaction on the terms set forth in the acquisition agreement.

Completion of the Acquisition is also subject to the satisfaction or waiver of certain other closing conditions contained in the acquisition agreement, including the absence of any law, judgement or similar governmental action that prevents, makes illegal or prohibits the consummation of the Acquisition.

There is no assurance that the required approvals will be received or that the other closing conditions will be satisfied or waived and, therefore, no assurance that the Company will complete the Acquisition within the expected time frame or at all. The failure to obtain the required approvals within 18 months following entry into the acquisition agreement or to satisfy or waive the other conditions contained in the acquisition agreement may result in the termination of the acquisition agreement.

The Company will be obligated to pay Empire U.S. $65.0 million if the acquisition agreement is terminated by either party due to a failure to obtain the required regulatory approvals within 18 months following execution of the acquisition agreement, or due to a final and non-appealable legal restraint that relates to the required regulatory approvals, or if Empire terminates the acquisition agreement based on a failure by the Company to perform its obligations with respect to obtaining required regulatory approvals, provided that, in each case, at the time of termination the Empire shareholder approval has been obtained and the other conditions to the Company’s obligation to complete the Acquisition have been satisfied or waived (except for those conditions that by their nature are to be satisfied at the closing and are then capable of being satisfied, and those conditions that have not been satisfied as a result of a breach of the acquisition agreement by the Company).

In addition, Empire’s directors owe fiduciary duties to the Empire shareholders (and other stakeholders), which may require the Empire board to consider competing offers to purchase the stock or assets of Empire. Prior to approval of the Acquisition by Empire’s shareholders, the directors of Empire have the right to recommend or accept an alternative offer that the Empire board determines constitutes a superior proposal, provided that before doing so Empire gives the Company an opportunity to negotiate revisions to the acquisition agreement. As a result, receipt by Empire of a superior proposal could result in an increase in the cash purchase price for the Acquisition or other revisions to the terms and conditions of the Acquisition or, alternatively, the termination of the acquisition agreement.

A termination of the acquisition agreement may have a negative effect on the price of the Installment Receipts, the Debentures and the Common Shares and will result in the redemption of the Debentures. In addition, if the closing of the Acquisition does not take place as contemplated, the Company could suffer other adverse consequences, including the loss of investor confidence.

For the purpose of financing the Acquisition, the Company obtained Acquisition Credit Facilities of $2.2 billion (U.S. $1.6 billion) in February 2016, and completed the $1.15 billion Debentures Offering in March 2016, including the exercise of an

2015 Annual Report	50
Algonquin Power & Utilities Corp. - Management's Discussion & Analysis

over-allotment. On March 9, 2016, upon issuing the Debentures (see Financial Statements note 25) and receiving the First Instalment, the Company reduced the aggregate commitments under the Acquisition Credit Facilities by $360.0 million (U.S. $263.6 million).

The Company expects to fund the cash purchase price of the Acquisition and the acquisition-related expenses with a combination of some or all of the following: (i) net proceeds of the first instalment under the Debenture Offering; (ii) net proceeds of any subsequent bond or other debt offerings; (iii) amounts drawn under the Acquisition Credit Facilities; and (iv) existing cash on hand and other sources available to the Corporation.

The commitment of the lenders to enter into the Acquisition Credit Facilities is subject to certain standard conditions which may result in such facilities becoming unavailable to the Company in certain circumstances. There is no guarantee that alternate sources of funding will be available to the Company or its affiliates at the desired time or at all, or on cost-efficient terms.

If the Acquisition Credit Facilities become unavailable to the Company, and the Company fails to obtain sufficient alternative financing, the Company may not be able to complete the Acquisition. The Company’s obligation to complete the Acquisition is not conditional on the Company obtaining financing on favourable terms or at all. In the event that the Company does not have sufficient financing to complete the Acquisition, upon satisfaction of all conditions to closing, and Empire terminates the acquisition agreement as a result, the Company will be obligated to pay Empire U.S. $65.0 million, in addition to potential liability for damages.

If a material amount of the final instalment for the Debentures is not paid by holders of Instalment Receipts and the Company is not able to quickly realize on the Debentures pledged to secure the obligation to pay the final instalment, the Company will not be able to use those proceeds to repay the Acquisition Credit Facilities. The foregoing, or any other inability to obtain alternate sources of funding to fund the Acquisition or replace the Acquisition Credit Facilities, may have a negative impact on the consolidated capitalization of the Company until such time as the Acquisition Credit Facilities have been repaid by the Company in full, and may negatively impact the financial performance of the Company, including the extent to which the Acquisition is accretive.

In addition, any movement in interest rates that could affect the underlying cost of these instruments may affect the expected accretion of the Acquisition. The Company may enter into hedging arrangements to mitigate this risk.

As a result of the pursuit and completion of the Empire acquisition, significant demands will be placed on the Company’s managerial, operational and financial personnel and systems. No assurance can be given that the Company’s systems, procedures and controls will be adequate to support the expansion of the Company’s operations resulting from the acquisition. The Company’s future operating results will be affected by the ability of its officers and key employees to manage changing business conditions and to implement and improve its operational and financial controls and reporting systems.

Although the acquisition agreement contains covenants on the part of Empire regarding the operation of its business prior to closing the Acquisition, the Company will not control Empire and its subsidiaries until completion of the Acquisition and Empire’s business and results of operations may be adversely affected by events that are outside of the Corporation’s control during the intervening period. Historic and current performance of Empire’s business and operations may not be indicative of success in future periods. The future performance of Empire may be influenced by, among other factors, weather, economic downturns, increased environmental regulation, turmoil in financial markets, unfavourable regulatory decisions, rising interest rates and other factors beyond the Corporation’s control. As a result of any one or more of these factors, among others, the operations and financial performance of Empire may be negatively affected which may adversely affect the future financial results of the Company.

The Company expects to incur a number of costs associated with completing the Acquisition. The substantial majority of these costs will be non-recurring expenses and will consist of transaction costs related to the Acquisition, including costs relating to the financing of the Acquisition and obtaining regulatory approval. Additional unanticipated costs may be incurred and the amounts may be material.

Although the Company has conducted what it believes to be a prudent and thorough level of investigation in connection with the Acquisition, an unavoidable level of risk remains regarding the accuracy and completeness of such information. While the Company has no reason to believe the information obtained from Empire or taken from the public disclosure record is misleading, untrue or incomplete, the Company cannot assure the accuracy or completeness of such information nor can the Company compel Empire to disclose events which may have occurred or may affect the completeness or accuracy of such information but which are unknown to the Company.

Asset Retirement Obligations

APUC and its subsidiaries complete periodic reviews of potential asset retirement obligations that may require recognition. As part of this process, APUC and its subsidiaries consider the contractual requirements outlined in their operating permits, leases, and other agreements, the probability of the agreements being extended, the ability to quantify such expense, the timing of incurring the potential expenses, as well as other factors which may be considered in evaluating if such obligations exist and in estimating the fair value of such obligations.

The Distribution Group’s facilities are operated with the assumption that their services will be required in perpetuity and there are no contractual decommissioning requirements. In order to remain in compliance with the applicable regulatory bodies, the Distribution Group has regular programs at each facility to ensure its equipment is properly maintained and replaced on a cyclical basis. These costs can generally be included in the facility’s rate base and thus the Distribution Group expects to be allowed to earn a return on such investment.

In conjunction with recent acquisitions and developed projects, the Company assumed certain asset retirement obligations. The asset retirement obligations mainly relate to legal requirements for: (i) removal of wind facilities upon termination of land leases; (ii) cut (disconnect from the distribution system), purge (clean of natural gas and PCB contaminants), and cap gas mains within the gas distribution and transmission system when mains are retired in place, or dispose of sections of gas main when removed from the pipeline system; (iii) clean and remove storage tanks containing waste oil and other waste contaminants; and (iv) remove asbestos upon major renovation or demolition of structures and facilities.

Environmental Risks

APUC and its subsidiaries face a number of environmental risks that are normal aspects of operating within the renewable power generation, thermal power generation, and utilities business segments, which have the potential to become environmental liabilities. Many of these risks are mitigated through the maintenance of an adequate insurance program, which includes property, equipment breakdown, environmental, and liability policies.

2015 Annual Report	51
Algonquin Power & Utilities Corp. - Management's Discussion & Analysis

The Generation Group’s ongoing operations and historic activities are subject to various environmental laws and regulations and are regulated by federal agencies such as the United States Environmental Protection Agency, FERC, NERC, Environment Canada, Fisheries and Oceans Canada; and State/Provincial Agencies, such as the New York State Department of Environmental Conservation (“NYSDEC”), California Air Resource Board, Connecticut Department of Environmental Protection (“CDEP”),  Illinois Department of Environmental Protection (“IDEP’), Pennsylvania Game Commission (“PGC”), Alberta Environment, Manitoba Conservation, Ontario Ministry of the Environment, Ontario Ministry of Natural Resources, among others.  Power generation facilities generate air emissions, noise, potential for flooding, spill risk, possible disruption of protected wildlife, along with the generation of industrial wastewater and certain amounts of hazardous wastes.

The Distribution Group faces environmental risks that are normal aspects of operating within its business segment. The primary environmental risks associated with the operation of an electrical distribution system are related to potential accidental release of mineral oil to the environment from non-operational events and the management of hazardous and universal waste in accordance with the various Federal, State and local environmental laws. Like most other industrial companies, the Distribution Group generates some hazardous wastes as a result of its operations. Under Federal and State Superfund laws, potential liability for historic contamination of property may be imposed on responsible parties jointly and severally, without fault, even if the activities were lawful when they occurred.

In order to monitor and mitigate these risks and to remain within the regulatory requirements appropriate for these assets, the Generation and Distribution Groups investigate promptly all reported accidental releases to take all required remedial actions and manages hazardous waste and universal waste streams in accordance with the applicable Federal and State Legislation.

The primary risks associated with the operation of gas distribution systems are related to uncontrolled natural gas releases, equipment damage by construction equipment/third parties or severe weather events. The gas distribution assets are regulated by the Pipeline Hazardous Material Safety Administration (PHMSA) under the United States Department of Transportation and their respective State regulations in which the assets are located. Natural Gas Distribution Systems are subject to detailed inspections by State Regulatory Agencies to ensure adherence to applicable regulations. State Regulator Agencies review the Company’s policies in reference to operation and maintenance, construction, training, emergency response, reporting, contractor management and measurements. The Distribution Group monitors all aspects of pipeline safety and quickly mitigates any identified concerns.

The primary risks associated with the operation of power generation facilities are related to uncontrolled contaminant releases (or above the permitted limits), not being in continued compliance with permits and licenses obligations such as, continuous emissions monitoring, periodic reporting/source testing, general performance/operating conditions, operations adjustments (wind projects) resulting from post construction wildlife mortality monitoring, dam safety, potential accidental release of mineral oil or other hazardous materials to the environment.

The Distribution Group’s ongoing operations and historic activities are subject to various federal, state and local environmental laws and regulations and are regulated by agencies such as the United States Environmental Protection Agency, the New Hampshire Department of Environmental Services (“NHDES”). Similar to other industrial companies, the gas and electric distribution utilities generate certain hazardous wastes. Under federal and state Superfund laws, potential liability for historic contamination of property may be imposed on responsible parties jointly and severally, without fault, even if the activities were lawful when they occurred. In the case of regulated utilities these costs are often allowed in rate case proceedings to be recovered from rate payers over a specified period.

Prior to their acquisition by the Distribution Group, the EnergyNorth Gas Utility, the Granite State Electric Utility, and the New England Gas System were named as potentially responsible parties for remediation of several sites at which hazardous waste is alleged to have been disposed as a result of historic operations of Manufactured Gas Plants (“MGP”) and related facilities. The Distribution Group is currently investigating and remediating, as necessary, those MGP and related sites where it is the lead project manager in accordance with plans submitted to the NHDES. The Distribution Group believes that obligations imposed on it because of those sites will not have a material impact on its results of operations or financial position.

The Distribution Group estimates the remaining undiscounted and unescalated cost of these MGP-related environmental cleanup activities will be $78.5 million which, at discount rates ranging from 2.5% to 4.2%, represents $71.5 million on a discounted basis, as the Distribution Group’s estimate of costs for known issues that has been accrued at December 31, 2015. By rate orders, the Regulator provided for the recovery of site investigation and remediation costs and accordingly, at December 31, 2015 the Company has reflected a regulatory asset of $116.7 million for the remediation of the MGP and related sites.

APUC’s policy is to record estimates of environmental liabilities when they are known or considered probable and the related liability is estimable.

Cycles and Seasonality

Generation Group

The Generation 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 Generation 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 Generation Group's solar generation facilities are impacted by seasonal fluctuations and year to year variability in the solar radiance. For instance, there are more daylight hours in the summer than there are in the winter resulting in higher production in the summer months. The ability of these facilities to generate income may be impacted by naturally occurring changes in solar radiance.

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

Distribution Group

The Distribution 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 Distribution Group’s demand for energy from its electric distribution systems is primarily affected by weather conditions and conservation initiatives. The Distribution 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 to revenues.

The Distribution 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.

2015 Annual Report	52
Algonquin Power & Utilities Corp. - Management's Discussion & Analysis

Not all regulatory jurisdictions in which the Distribution Group operates have approved mechanisms to mitigate demand fluctuations.

Development and Construction Risk

The Generation Group actively engages in the development and construction of new power generation facilities. The current pipeline of projects either currently in construction or in development is $1.8 billion and are mainly renewable solar and wind projects.  There is always a risk that material delays and/or cost overruns could be incurred in any of the projects planned or currently in construction affecting the company’s overall performance.  Examples of inherent risks pertaining to power generation facility development can include: technical issues with the interconnection utility, unfavorable permitting results or delays emanating from State, Provincial or Federal agency interface, construction delays or cost overruns, equipment performance outside of expectations, and land owner disputes. The Generation Group mitigates these risk through its due diligence processes, sound project management principals and appropriate contingency plans and reserves.

The strength and consistency of the wind resource will vary from the estimate set out in the initial wind studies that were relied upon to determine the feasibility of the wind facility. If weather patterns change or the historical data proves not to accurately reflect the strength and consistency of the actual wind, the assumptions underlying the financial projections as to the amount of electricity to be generated by the facility may be different and cash could be impacted.

The amount of solar radiance will vary from the estimate set out in the initial solar studies that were relied upon to determine the feasibility of the solar facility. If weather patterns change or the historical data proves not to accurately reflect the strength and consistency of the solar radiance, the assumptions underlying the financial projections as to the amount of electricity to be generated by the facility may be different and cash could be impacted.

For certain of its development projects, the Generation Group relies on financing from third party Tax Equity Investors. These investors typically provide funding upon commercial operation of the facility. Should certain facilities not meet the conditions required for tax equity funding, expected returns from the facilities may be impacted.

Regulatory approvals can be challenged by a number of mechanisms which vary across state and provincial jurisdictions.  Such permitting challenges could identify issues that may result in permits being modified or revoked. The Amherst Wind Project in Ontario is currently the subject of an appeal to the ERT for which a decision is expected in April 2016. If the ERT finds that the project will cause serious and irreversible harm to the environment or human health, the tribunal has the authority to revoke the provincial environmental permit. If the ERT has concerns, the project would expect to be given the opportunity to make submissions or changes to the project to address the tribunals concerns.

Obligations to Serve

The Distribution Group may have facilities located within areas of the United States experiencing growth. These utilities may have an obligation to service new residential, commercial and industrial customers. While expansion to serve new customers will likely result in increased future cash flows, it may require significant capital commitments in the immediate term. Accordingly, the Distribution Group may be required to solicit additional capital or obtain additional borrowings to finance these future construction obligations.

2015 Annual Report	53
Algonquin Power & Utilities Corp. - Management's Discussion & Analysis

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.

Trafalgar Proceedings

Trafalgar commenced an action in 1999 in U.S. District Court against various Algonquin entities in connection with, among other things, the sale of the Trafalgar Class B Note by Aetna Life Insurance Company to the Algonquin entities and in connection with the foreclosure on the security for the Trafalgar Class B Note which includes interests in the Trafalgar entities and in the hydroelectric generating facilities in New York (the “Trafalgar Hydro Facilities”). Over the past 16 years there have been various legal proceedings and appeals in connection with this matter. Both the Algonquin entities and Trafalgar had certain motions before the Bankruptcy Court seeking determinations on a number of matters. On November 13, 2015, the Bankruptcy Court entered judgment that: (1) grants Algonquin’s motion for summary judgment; (2) denies Trafalgar’s’ motion for summary judgment; and (3) dismisses Trafalgar’s Adversary Complaint on the merits. Trafalgar has appealed the Judgment. Trafalgar has brought a motion for reconsideration of this judgment.

Additionally, Trafalgar has alleged in various pleadings before the Bankruptcy Court that the Algonquin entities has mismanaged the operations of the Trafalgar Hydro Facilities (now sold as noted below) under that certain Management Agreement dated January 15, 1996. No demand has been made based on these allegations. Any such claims are subject to an arbitration clause under the Management Agreement. Algonquin denies any liability under either the 1995 agreement or the Management Agreement and will continue to vigorously defend against these claims.

The Bankruptcy Court has approved the sale of all seven of the Trafalgar Hydro Facilities all of which have now been closed. The parties are attempting to settle this long standing lawsuit through mediation.

Long Sault global adjustment claim

In December 2012, N-R Power and Energy Corporation, 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 (“GA”) as a price escalator. On March 12, 2015, the Ontario Superior Court of Justice ruled that the methodology that the OEFC used from January 1, 2011, onward to calculate payments under Long Sault's PPA, and those of other producers, did not comply with the terms of those PPAs. The decision further requires the OEFC to revert to its pre-2011 methodology for calculating payments and to pay producers the difference between the payments calculated by the OEFC since 2011 and the amount of the payments they would have received using the pre-2011 methodology, plus interest and costs. On April 10, 2015, the OEFC appealed to the Court of Appeal to set aside the Divisional Court’s judgment of March 12, 2015. The appeal was heard on December 14 and December 15, 2015; the Court has reserved judgment.

Côte Ste-Catherine Water Lease Dues

In October 2011, the Quebec Court of Appeal ordered a subsidiary of APUC to pay approximately $5.4 million (including interest) to the Government of Quebec relating to water lease payments that the APUC subsidiary has been paying to the St. Lawrence Seaway Management Corporation (“Seaway Management”) under its water lease with Seaway Management in prior years.

The water lease with Seaway Management contains an indemnification clause which management believes mitigates this claim and management intends to vigorously defend its position.  As a result, the probability of loss, if any, and its quantification cannot be estimated at this time but could range from $nil to $6.8 million. In 2012, the Company paid an amount of $1.9 million to the Government of Quebec in relation to the early years covered by the claim in order to mitigate the impact of accruing interests on any amount ultimately determined to be payable or recoverable.

2015 Annual Report	54
Algonquin Power & Utilities Corp. - Management's Discussion & Analysis

QUARTERLY FINANCIAL INFORMATION

The following is a summary of unaudited quarterly financial information for the eight quarter ended December 31, 2015:

(all dollar amounts in $ millions except per share information)	1st Quarter 2015		2nd Quarter 2015		3rd Quarter 2015			4th Quarter 2015
Revenue	$	381.9	$	196.2	$	189.6		$	260.3
Adjusted EBITDA	114.5		81.1		70.2			109.6
Net earnings / (loss) attributable to shareholders from continuing operations	43.1		20.6		16.7			38.1
Net earnings / (loss) attributable to shareholders	43.1		19.9		16.5			38.0
Net earnings / (loss) per share from continuing operations	0.16		0.07		0.06			0.14
Net earnings / (loss) per share	0.16		0.07		0.05			0.14
Adjusted net earnings	42.5		22.2		17.3			39.7
Adjust net earnings per share	0.17		0.08		0.06			0.15
Total Assets	4,531.4		4,396.5		4,759.0			4,991.7
Long term debt1	1,482.7		1,440.3		1,613.3			1,486.8
Dividend declared per common share	0.11		0.12		0.13			0.13
	1st Quarter 2014		2nd Quarter 2014		3rd Quarter 2014			4th Quarter 2014
Revenue	$	343.0	$	188.6	$	151.6		$	259.3
Adjusted EBITDA	97.5		66.4		41.4			84.3
Net earnings / (loss) attributable to shareholders from continuing operations	35.6		15.3		(6.1		)	33.1
Net earnings/(loss) attributable to shareholders	35.9		14.6		(6.3		)	31.6
Net earnings / (loss) per share from continuing operations	0.16		0.06		(0.04		)	0.13
Net earnings/(loss) per share	0.17		0.06		(0.04		)	0.13
Adjusted net earnings	36.8		16.6		(0.4		)	35.2
Adjust net earnings per share	0.17		0.07		(0.01		)	0.14
Total Assets	3,644.3		3,553.6		3,799.3			4,105.1
Long term debt1	1,400.9		1,381.0		1,404.3			1,271.7
Dividend declared per common share	0.09		0.09		0.10			0.10

1 Long term debt includes current and long term portion of debt

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 $151.6 million and $381.9 million over the prior two year period. A number of factors impact quarterly results including acquisitions, seasonal fluctuations, hydrology 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 $43.1 million and a net loss of $6.3 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

At the end of the fiscal year ended December 31, 2015, 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

2015 Annual Report	55
Algonquin Power & Utilities Corp. - Management's Discussion & Analysis

on that evaluation, the CEO and the CFO have concluded that as of December 31, 2015, APUC’s disclosure controls and procedures are effective.

INTERNAL CONTROLS OVER FINANCIAL REPORTING

APUC’s internal control over financial reporting is a process designed to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles.

A company’s internal control over financial reporting includes those policies and procedures that (i) pertain to the maintenance of records that, in reasonable detail, accurately and fairly reflect the transactions and dispositions of the assets of APUC; (ii) provide reasonable assurance that transactions are recorded as necessary to permit preparation of financial statements in accordance with generally accepted accounting principles, and that receipts and expenditures of APUC are being made only in accordance with authorizations of management and directors of APUC; and (iii) provide reasonable assurance regarding prevention or timely detection of unauthorized acquisition, use, or disposition of APUC’s assets that could have a material effect on the financial statements.

Because of its inherent limitations, internal control over financial reporting may not prevent or detect all misstatements. Additionally, projections of any evaluation of effectiveness to future periods are subject to the risk that controls may become inadequate because of changes in conditions, or that the degree of compliance with the policies or procedures may deteriorate.

During the year ended December 31, 2015, 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. On May 14, 2013, the Committee of Sponsoring Organizations of the Treadway Commission (COSO) published


an updated Internal Control - Integrated Framework (2013) and related illustrative documents. The company adopted the new framework in 2014.

Management conducted an evaluation of the design and operation of APUC’s internal control over financial reporting as of December 31, 2015 based on the criteria set forth in Internal Control – Integrated Framework (2013) issued by the Committee of Sponsoring Organizations of the Treadway Commission. This evaluation included review of the documentation of controls, evaluation of the design effectiveness of controls, testing of the operating effectiveness of controls, and a conclusion on this evaluation. Based on this evaluation, management has concluded that APUC’s internal control over financial reporting was effective as of December 31, 2015.

CRITICAL ACCOUNTING ESTIMATES AND POLICIES

The preparation of consolidated financial statements requires management to make estimates and assumptions that affect the reported amounts of assets and liabilities, related amounts of revenues and expenses, and disclosure of contingent assets and liabilities.  Significant areas requiring the use of management estimates relate to the useful lives and recoverability of depreciable assets, 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 are discussed in Note 1 to the consolidated financial statements. Management believes the following accounting policies involve the application of critical accounting estimates. Accordingly, these accounting estimates have been reviewed and discussed with the Audit Committee of the Board of Directors of APUC.

Estimated useful lives and recoverability of Long-Lived Assets, Intangibles and Goodwill

The Company makes judgments a) to determine the recoverability of a development project, and the period over which the costs are capitalized during the development and construction of the project, b) to assess the nature of the costs to be capitalized, c) to distinguish individual components and major overhauls, and d) to determine the useful lives or unit-of-production over which assets are depreciated.

Depreciation rates on utility assets are subject to regulatory review and approval, and depreciation expense is recovered through rates set by ratemaking authorities. The recovery of those costs is dependent on the ratemaking process.

The carrying value of long-lived assets, including intangible assets and goodwill, is reviewed whenever events or changes in circumstances indicate that such carrying values may not be recoverable, and at least annually for goodwill. Some of the factors APUC considers as indicators of impairment include a significant change in operational or financial performance, unexpected outcome from rate orders, natural disasters, energy pricing and changes in regulation. When such events or circumstances are present, the Company assesses whether the carrying value will be recovered through the expected future cash flows. If the facility includes goodwill, the fair value of the facility is compared to its carrying value. Both methodologies

2015 Annual Report	56
Algonquin Power & Utilities Corp. - Management's Discussion & Analysis

are sensitive to the forecasted cash flows and in particular energy prices, long-term growth rate and, discount rate for the fair value calculation.

Valuation of Deferred Tax Assets

In assessing the realization of deferred tax assets, management considers whether it is more likely than not that some portion or all of the deferred tax assets will not be realized and provides any necessary valuation allowances as required.

Accounting for Rate Regulation

Accounting guidance for regulated operations provides that rate-regulated entities account for and report assets and liabilities consistent with the recovery of those incurred costs in rates if the rates established are designed to recover the costs of providing the regulated service and if the competitive environment makes it probable that such rates can be charged and collected. This accounting guidance is applied to the Distribution Group’s operations.

Certain expenses and revenues subject to utility regulation or rate determination normally reflected in income are deferred on the balance sheet as regulatory assets or liabilities and are recognized in income as the related amounts are included in service rates and recovered from or refunded to customers. Regulatory assets and liabilities are recorded when it is probable that these items will be recovered or reflected in future rates. Determining probability requires significant judgment on the part of management and includes, but is not limited to, consideration of testimony presented in regulatory hearings, proposed regulatory decisions, final regulatory orders and industry practice. If events were to occur that would make the recovery of these assets and liabilities no longer probable, these regulatory assets and liabilities would be required to be written off or written down.

Unbilled Energy Revenues

Revenues related to natural gas, electricity and water delivery are generally recognized upon delivery to customers. The determination of customer billings is based on a systematic reading of meters throughout the month. At the end of each month, amounts of natural gas, energy or water provided to customers since the date of the last meter reading are estimated, and the corresponding unbilled revenue is recorded. Factors that can impact the estimate of unbilled energy include, but are not limited to, seasonal weather patterns compared to normal, total volumes supplied to the system, line losses, economic impacts, and composition of customer classes. Estimates are reversed in the following month and actual revenue is recorded based on subsequent meter readings.

Derivatives

APUC uses derivative instruments to manage exposure to changes in commodity prices, foreign exchange rates, and interest rates. Management’s judgment is required to determine if a transaction meets the definition of a derivative and, if it does, whether the normal purchases and sales exception applies or whether individual transactions qualify for hedge accounting treatment. Management’s judgment is also required to determine the fair value of derivative transactions.  APUC determines the fair value of derivative instruments based on forward market prices in active markets adjusted for nonperformance risk. A significant change in estimate could affect APUC’s results of operations if the hedging relationship was considered no longer effective.

Pension and Post-employment Benefits

The obligations and related costs of defined benefit pension and post-employment benefit plans are calculated using actuarial concepts, which include critical assumptions related to the discount rate, mortality rate, compensation increase, expected rate of return on plan assets and medical cost trend rates. These assumptions are important elements of expense and/or liability measurement and are updated on an annual basis, or upon the occurrence of significant events. The Company used the new mortality improvement scale (MP-2015) recently released by the Society of Actuaries adjusted to reflect the 2015 Social Security Administration ultimate improvement rates.

Sensitivities

The sensitivities of key assumptions used in measuring accrued benefit obligations and benefit plan cost for 2015 are outlined in the following table. They are calculated independently of each other. Actual experience may result in changes in a number of assumptions simultaneously. The types of assumptions and method used to prepare the sensitivity analysis has not changed from previous periods and is consistent with the calculation of the retirement benefit obligations and net benefit plan cost recognized in the consolidated financial statements.

2015 Annual Report	57
Algonquin Power & Utilities Corp. - Management's Discussion & Analysis

	2015 OPEB Plans				2015 Pension Plans
(all dollar amounts in $ millions)	Accumulated Postretirement Benefit Obligation		Net Periodic Postretirement Benefit Cost		Accrued Benefit Obligation		Net Periodic Pension Cost
Discount Rate
1% increase	(9.6	)	(1.2	)	(26.6	)	(1.2	)
1% decrease	12.1		1.3		32.6		3.5
Future compensation rate
1% increase	—		—		0.2		1.3
1% decrease	—		—		(0.2	)	(0.9	)
Expected return on plan assets
1% increase	—		(0.1	)	—		(1.8	)
1% decrease	—		0.1		—		1.8
Life expectancy
1% increase	6.7		1.0		17.8		2.8
1% decrease	(6.2	)	(1.0	)	(19.3	)	(2.0	)
Health care trend
1% increase	10.8		2.0		—		—
1% decrease	(8.7	)	(1.7	)	—		—

Business Combinations

The Company has completed a number of business acquisitions in the past few years. Management's judgment is required to estimate the purchase price, to identify and to fair value all assets and liabilities acquired. The determination of the fair value of assets and liabilities acquired is based upon management’s estimates and certain assumptions generally included in a present value calculation of the related cash flows. A significant change in estimate could affect APUC’s results of operations.

Additional disclosure of APUC’s critical accounting estimates is also available on SEDAR at www.sedar.com and on the APUC website at www.AlgonquinPowerandUtilities.com.

2015 Annual Report	58
Algonquin Power & Utilities Corp. - Management's Discussion & Analysis