Generation. Transmission. Distribution.

Investor Day - November 25, 2014

ContentsAgenda Page 1

Caution Regarding Forward-Looking Information Page 2

Key Selected Financial Information Page 5

Biographies Page 6

Presentation Slides Page 12

Agenda: Algonquin Power & Utilities Investor MorningTuesday, November 25, 2014

8:00 – 8:30 a.m. Registration Coffee and Continental Breakfast

8:30 – 8:35 a.m. Welcome and Opening Remarks Kelly Castledine, Director, Investor Relations

8:35 – 9:30 a.m. Algonquin Power & Utilities Executive Panel Ian Robertson, CEO Chris Jarratt, Vice Chair David Bronicheski, CFO

9:30 – 10:30 a.m. Generation Strategy and Operations Mike Snow, President Business Development Jeff Norman, Vice President, Business Development Financials Todd Mooney, Vice President, Finance & Administration

10:30 – 10:45 a.m. Break

10:45 – 11:45 p.m. Distribution Strategy and Operations David Pasieka, President Distribution Growth Peter Eichler, Director, Strategic Initiatives Financials Gerald Tremblay, Vice President, Finance & Administration

11:45 – 12:15 p.m. Transmission Strategy Ian Robertson, CEO Transmission Opportunities Dick Leehr, President, Pipelines & Transmission 12:30 – 1:00 p.m. Lunch Presentation Energy Storage: Charlie Ashman, Vice President, Technology

Energy opportunities in an evolving utility landscape

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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 adjusted net earnings", “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 adjusted net earnings”, “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 adjusted net earnings”, “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

2

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 adjusted net earnings”, “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 metric used by many investors to compare companies on the basis ofability 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, unrealized gains or losses on derivative financial instruments, non-cash write downs of intangibles and property, plant and equipment, earnings attributable to non-controlling interests, gains or losses on foreign exchange, earnings or loss from discontinued operations and other infrequent items unrelated to normal ongoing operations. APUC adjusts for these factors as they are typically 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 metric 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, unrealized gains or losses on derivative financial instruments and interest rate swaps, acquisition costs, litigation expenses, non-cash write downs of intangibles and property, plant and equipment, earnings or loss from discontinued operations and other

3

infrequent items unrelated to normal operations 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 metric 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 infrequent items unrelated to normal operations 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 is a non-GAAP metric 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 metric 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.

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Financial Summary

Nine months ended September 30

Year ended December 31

2014 2013 2013 2012

Revenue $ 684.2 $ 470.0 $ 675.3 $ 348.8

Adjusted EBITDA1 206.2 159.6 226.9 88.1

Cash provided by operating activities 96.3 70.5 98.9 63.0

Adjusted funds from operations1 140.6 107.1 153.5 66.8

Net earnings attributable to shareholders

from continuing operations 44.8 42.4 62.3 13.5

Net earnings attributable to Shareholders 44.1 7.1 20.3 14.5

Adjusted net earnings1 53.2 40.6 60.9 18.9

Dividends declared to Common

Shareholders

57.5 50.8 68.3 50.2

Per share

Basic net earnings from continuing

operations $ 0.18 $ 0.19 $ 0.28 $ 0.08

Basic net earnings $ 0.18 $ 0.02 $ 0.07 $ 0.09

Adjusted net earnings1,2 $ 0.22 $ 0.18 $ 0.27 $ 0.11

Diluted net earnings $ 0.18 $ 0.02 $ 0.07 $ 0.09

Cash provided by Operating Activities2 $ 0.46 $ 0.35 $ 0.48 $ 0.40

Adjusted funds from operations1,2 $ 0.64 $ 0.51 $ 0.72 $ 0.42

Dividends declared to Shareholders $ 0.27 $ 0.25 $ 0.33 $ 0.30

Total Assets $ 3,808.5 $ 3,156.4 $ 3,472.6 $ 2,779.0

Total Liabilities3 (includes current portion) 1,413.5 1,092.0 1,255.6 770.8

1 APUC uses adjusted EBITDA, adjusted net earnings and adjusted funds from operations to enhance assessment and understanding of the operating

performance of APUC without the effects of certain accounting adjustments which are derived from a number of non-operating factors, accounting

methods and assumptions. ("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 Long term debt includes current and long term portion of debt and convertible debentures

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Algonquin Power & Utilities: Biographies

Ian Robertson, Chief Executive Officer

Ian Robertson serves as Chief Executive Officer of Algonquin Power & Utilities Corp. (APUC). He is a founder and principal of Algonquin Power Corporation Inc., an independent power developer, which was formed in 1988 and is the predecessor organization to APUC.

Ian has over 25 years of experience in the development, financing, acquisition and operation of electric power generating projects both in North America and internationally. He is an electrical engineer and holds a Professional Engineering designation through his Bachelor of Applied Science awarded by the University of Waterloo and a Master of Business Administration from York University’s Schulich School of Business. In addition, Ian was awarded a Chartered Financial Analyst designation in 2001. Ian received a Chartered

Director designation from McMaster University in 2008. Consistent with his commitment to continuing education, Ian is currently pursuing a Master of Laws at the University of Toronto, Law School.

In addition to his principal occupation as Chief Executive Officer of Algonquin Power & Utilities Corp., Ian has served as a director on a number of Boards of Directors for public companies in the electrical generation and oil and gas sectors, and is a member of the Board of Directors of the American Gas Association.

Chris Jarratt, Vice Chair

Chris was appointed Vice Chair of Algonquin in December, 2009. Chris is a founder and principal of Algonquin Power Corporation Inc., a private independent power developer formed in 1988, which was a predecessor organization to Algonquin. Chris has 30 years of experience in the development, financing, acquisition and operation of power generating and utility projects in North America. Chris is a water resources engineer who holds a Professional Engineer designation in Ontario and an Honours Bachelor of Science degree from the University of Guelph. Chris also holds a Chartered Director designation, which was awarded by McMaster University in 2009.

6

David Bronicheski, Chief Financial Officer

David joined Algonquin Power & Utilities Corp. in 2007 and is responsible for all aspects of planning, directing, implementing, evaluating, and reporting on the company’s financial performance. David has over 26 years of senior management experience including 14 years in the cable television & telecommunications industries. He has held various senior management and finance positions within the telecommunications industry including Executive Vice President and Chief Financial Officer of a publicly traded telephone, cable television and internet service provider. David holds a Bachelor of Arts in economics (cum laude), a Bachelor of Commerce degree, and an MBA. He is also a Chartered Professional Accountant (CPA, CA).

Kelly Castledine, Director, Investor Relations

Kelly joined Algonquin Power & Utilities Corp. in 2005 as Director, Investor Relations and is responsible for the development and execution of the overall Investor Relations and Communications program for Algonquin Power & Utilities Corp. Kelly has over 15 years of experience in investor relations, communications, and corporate governance & policy with North American businesses. She gained her experience in the information technology, pharmaceutical and independent power industries. Kelly holds an Honours Bachelor of Commerce degree from the DeGroote School of Business at McMaster University, and holds the Certified Professional in Investor Relations designation from Western University’s Ivey School of Business.

7

Mike Snow, President, Generation

Mike joined Algonquin Power & Utilities Corp. in 2011 as President of Algonquin Power Co. and is responsible for all aspects of strategy, business development, operations, asset management, human resources, and evaluating and reporting on growth and operational activities. Mike has led both industrial and consumer organizations focused on growth and international operations in Mexico, South America, and Asia, while driving culture change and building strong leadership teams. Mike holds a Bachelor of Science Degree in Math from Dalhousie University, a Bachelor of Engineering Degree (Mechanical) from the Technical University of Nova Scotia, and a Masters of Business Administration from the Richard Ivey School of Business – University of Western Ontario. Jeff Norman, Vice President, Business Development

Jeff co-founded the Algonquin Power Venture Fund in 2003 and joined Algonquin Power Co. in 2008. Jeff is focused on building a portfolio of energy-based investments in North America. Jeff is responsible for assessing the economic viability of development opportunities, negotiating the terms and conditions for project acquisitions, implementing project financing strategies, responding to requests for proposals from utilities, and negotiating key project contracts. Jeff has over 22 years of experience and has reviewed the economic merits of hundreds of renewable energy projects. Jeff holds an Honours Bachelor of Arts degree from the University of Waterloo, a Masters of Accounting degree, and is a CPA/CA.

8

Todd Mooney, Vice President, Finance & Administration

Todd joined Algonquin Power Co. in 2012 and has overall accountability for financial operations, including the Financial Planning & Analysis, Accounting, Production Reporting, and Administration. Todd previously spent 11 years in the mobile computing industry, leading finance teams in France, the UK, USA and Canada. Todd is active in the community, volunteering for a community environmental association and having served on the Board of Directors for various not-for-profits. Todd holds a Master of Accounting degree and is a Chartered Professional Accountant (CA, CPA).

Charles Ashman, Vice President, Technology

Charlie re-joined Algonquin Power Co. in 2012 as Vice President of Technology; a key leadership position providing advisory and oversight support to the senior executive team. Prior to rejoining the company, Charlie provided strategic consulting and technical advisory services to a portfolio of alternative energy clients and was instrumental in the successful repowering of the Windsor Locks cogeneration facility. Charlie graduated from the United States Merchant Marine Academy in 1977 with a degree in Marine Engineering. He also holds an MBA from the University of Connecticut, and a Six Sigma Black Belt Certificate from Villanova University. He formerly served as a Lieutenant in the United States Navy Reserve.

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David Pasieka, President, Distribution

David joined Algonquin Power & Utilities Corp. in 2010 as President of Liberty Utilities. As its President, David is focused on acquiring and managing a portfolio of regulated Water, Natural Gas and Electrical distribution companies throughout the United States. David has global experience in sales, marketing, integration, P&L, operations and customer service. He has led many organizations while integrating people, policies, and processes to encourage the steady growth of the organization. David holds a Bachelor of Science Degree from the University of Waterloo, Masters of Business Administration from the Schulich School of Business – York University, and a Chartered Director designation from McMaster University.

Peter Eichler, Director, Strategic Initiatives Peter joined Liberty Utilities in 2009. His roles have focused on the development of rate case strategy, and fostering and strengthening regulatory relationships throughout the United States. Peter has provided testimony in rate cases, acquisition dockets, and other strategic dockets before seven regulatory jurisdictions. In his current role, Peter focuses on the development of alternative fuel strategies, including the development of a virtual pipeline platform. Prior to joining Liberty Utilities, Peter developed significant financial, operational, and regulatory expertise in the utility industry working for some of the largest electric distribution companies in Ontario. Peter holds a Bachelor of Commerce Degree, a Masters of Business Administration, and is a Certified Management Accountant.

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Gerald Tremblay, Vice President, Finance & Administration

Gerald joined Algonquin Power & Utilities Corp. in 2000. He has overall accountability for the financial operations of Liberty Utilities, including the Accounting, Finance, and Administration departments. Gerald has over 20 years of experience in increasingly senior positions within the retail, energy, and utilities industries. He earned a Bachelor’s degree in Social Science with honours in Economics and is a Chartered Professional Accountant (Certified General Accountant).

Dick Leehr, President, Pipelines & Transmission

Dick Leehr is the newly announced President of Liberty Utilities (Pipeline & Transmission) Corp. based in Londonderry, New Hampshire. Previously he served as President of Liberty Energy Utilities – NH. Prior to joining Liberty, Dick served as a consultant for utilities developing northeast infrastructure projects drawing from the Marcellus /Utica shale region. He has also served in progressive, challenging senior executive capacities in the interstate gas pipeline industry over his 40 year career. More recently, Dick served as President of Millennium Pipeline Company LLC (2005-2010) and was responsible for the revival, development, construction and eventual operations of this new competitive entrant to serve the premium New York markets. Dick is a graduate of John Carroll University.

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INVESTOR DAY2014

Generation Transmission Distribution

FOCUSED GROWTH

EXECUTIVE PANEL

Ian RobertsonChief Executive Officer

Chris JarrattVice Chair

David BronicheskiChief Financial Officer

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The utility company most admired by customers,

communities and investors for our people, passion and

performance

A must-hold investment security in the portfolio of every long

minded investor

VISION

Our Vision

CapitalMarketsImpact

3

13

WHAT HAS CHANGED?

5

ALGONQUIN POWER & UTILITIES

6

Predictable and growing earnings as a national US

distribution utility

State regulated

50% of 2014 EBITDA

100% US

$1.8 billion utility assets

480,000 connections

$1.1 billion investment potential through acquisition and organic CAPEX pipeline

Attractive and growing returns from renewable

power generation portfolio

Non-regulated

50% of 2014 EBITDA

25% Canada / 75% US

$1.7 billion investment in 1,100 MW gross installed capacity

$1.2 billion investment potential through 500MW development pipeline

A GROWTH FOCUSED GENERATION, TRANSMISSON AND DISTRIBUTION UTILITY COMPANY

D I S T R I B U T I O NG E N E R AT I O N T R A N S M I S S I O N

Attractive risk-adjusted returns from regulated

transmission utility assets

Federal /State regulated

Natural gas pipelines and electrical transmission

North American focus

$450 million investment potential through development pipeline

14

EVOLUTION OF THE BOARD OF DIRECTORS

7

Masheed SaidiFormer Chief Operating Officer and Executive Vice President of U.S. Transmission for National Grid USA.

Dilek SamilFormer Executive Vice President and Chief Operating Officer of NV Energy

15

9

TOTAL SHAREHOLDER RETURN

GROWTH IN ASSETS

46%46%

GROWTH IN ADJUSTED NET EARNINGS

21%21%

31%31%

DELIVERED LTMTARGET

>10%>10%

~15%~15%

7‐10%7‐10%

2014 BY THE NUMBERS

29%29%~15%~15% GROWTH IN ADJUSTED EBITDA

10

SHAREHOLDER VALUE TRIPLED SINCE 2008

Value of $100 invested in 2008

TOTAL RETURN PERFORMANCE

Algonquin Power & Utilities 

S&P/TSX Composite Index

S&P/TSX Utilities Index

TOTAL SHAREHOLDER RETURN

16

COST OF CAPITAL

1 Ranges based on independent estimates of cost of capital using CAPM and Dividend Growth models

2 Canadian IPP Peers include: BEP.UN, NPI, INE, BLX, RNW

3 U.S. Yield Cos include: NYLD, TERP, ABY, NEP, PEGI 11

4.00%

4.50%

5.00%

5.50%

6.00%

6.50%

7.00%

7.50%

8.00%

AQN Canadian IPPPeers

U.S. YieldCos.

FORECAST GROWTH IN ASSETS AND EBITDA

12

15% Growth Target vs. Planned Net Asset Growth

15% Growth Target vs. Expected EBITDA from Planned Growth

17

ADMINISTRATION COSTS

22.22%

10.36% 9.17%

0%

5%

10%

15%

20%

25%

$0

$5,000

$10,000

$15,000

$20,000

$25,000

$30,000

$35,000

2012 2013 2014Administration expenses Centralization of servicesAs a percent of EBITDA

13

18

0

100

200

300

400

500

1-Jan-09 1-Jan-10 1-Jan-11 1-Jan-12 1-Jan-13 1-Jan-14

EXECUTIVE COMPENSATION VS. PERFORMANCE

Valu

e of

$10

0 in

vest

ed in

Jan

uary

200

9

15

SOURCES & USES OF CAPITAL

16

Sources of CapitalUses of Capital

Debt

Cash from Ops

Tax Equity

Preferred Shares

Common Equity

Odell Wind

Park Water

Distribution CapitalGeneration Capital

19

CAPITAL STRUCTURE

S&P: BBB

000's

Long term liabilities 1,413,473 46.7%Preferred shares 213,807 7.1%Equity 1,400,261 46.3%

Total capitalization 3,027,541 100.0%

September 30, 2014

INVESTMENT GRADE DEBT PLATFORMS: APCo bond platform

Canadian debt capital market public bond Liberty Utilities bond platform

U.S. private placement market bond

STRONG ACCESS TO EQUITY CAPITAL MARKETS Rate reset preferred shares Dividend paying common shares

17

SHAREHOLDER VALUE CREATION

18

20

ALGONQUIN POWER & UTILITIES

19

Predictable and growing earnings as a national US

distributionutility

Attractive and growing returns from renewable

power generation portfolio

A GROWTH FOCUSED GENERATION, DISTRIBUTION AND TRANSMISSION UTILITY COMPANY

D I S T R I B U T I O NG E N E R AT I O N T R A N S M I S S I O N

Attractive risk-adjusted returns from regulated transmissionutility assets

QUESTIONS

21

INVESTOR DAY2014

Generation

FOCUSED GROWTH

Mike SnowPresidentGeneration

Jeff NormanVice President, Business DevelopmentGeneration

Todd MooneyVice President, Finance & AdministrationGeneration

22

Mike SnowPresident

GENERATION

AGENDA

Value creation Market dynamics Portfolio diversification Generation strategy Development plans Financial indicators

24

23

25

PROVEN TRACK RECORD IN VALUE CREATION

Capital Efficiency Increasing with Growth

2010 – 2013• EBITDA growth from $67M -

$129M• $600M capital spend across

five wind projects• St. Leon II, Sandy Ridge,

Minonk, Senate, Shady Oaks

13.6x12.4x 12.3x

11.1x

0.0 2.0 4.0 6.0 8.0

10.0 12.0 14.0 16.0

2010 2011 2012 2013

DELIVERING 267 MW OF 2014 / 2015 ACCRETIVE PROJECTS

26

St. Damase Wind: 24 MW• $49 million CapEx (net of CRCE)• 5 year average EPS of $0.78

Morse Wind: 23 MW• $81 million CapEx• 5 year average EPS of $0.76

Bakersfield Solar: 20 MW• $66 million CapEx / $40 million net• 5 year average EPS of $1.24

Odell Wind: 200 MW• $362 million CapEx / $164 million net• 5 year average EPS of $1.28

COD: Q1 2015

COD: Q1 2015

COD: Q4 2015

24

Larger rotors improve net capacity factor Higher towers in use:

future - 140m in Europe Deep arrays software

improves yield Emerging technology

with direct drive turbines

27

WIND TECHNOLOGY POSITIVELY IMPACTS LCOE

$135$124

$71 $70 $70

020406080

100120140160

2009 2010 2011 2012 2013 2014

LCO

E ($

/MW

h)Significant decline in LCOE in 5 years

$37- $81

Sustainable cost reductions achieved Improved manufacturing efficiencyLower cost materials Panel redesign

28

DECLINING SOLAR COSTS POSITIVELY IMPACT LCOE

$0.76/W $0.22/W $0.33/W $1.31/W

Polysilicon / Wafer Cell Module Total

$0.22/W $0.15/W $0.16/W $0.53/W

Secure LT wafer supply Lower cost silicon Supply diversification

Reduce raw mat’l cost Reduce raw mat’l usage Increase throughput

Reduce cell to module power loss Reduce raw mat’l cost Redesign modules

2011 LCOE: $157

2014 LCOE:$72 - $86

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Key Market Drivers

Wind / Solar LCOE at or near grid parity Continued U.S. renewable demand

RPS step grows availability of utility PPAs EPA measures on reducing GHG U.S. wind growth at 8 GW / yr without PTCs

Provincial utilities set Canadian demand

29

POSITIVE OUTLOOK FOR NORTH AMERICAN RENEWABLES

Wind & Solar Drive Renewable Growth

Renewable capacity grows 52% to 2040 Solar leads growth: 8 to 48 GW Wind capacity from 60 – 87 GW Growth after 2025 absent state RPS

WIND DIVERSIFICATION IMPROVES PORTFOLIO CERTAINTY

Wind projects located in areas of greater wind speed certainty

30

Greater wind speed certainty

Less wind speed certainty

Algonquin Wind Projects

26

60 70 80 90 100 110 120 130 140

WIND DIVERSIFICATION IMPROVES PORTFOLIO CERTAINTY

Portfolio effect improves production stability

P90 portfolio energy is 5.6% > P90 13 Sites

Further diversification: 5 technologies 8 creditworthy offtakers Seasonality

Variability of production of

individual projects

Variability as a portfolio

31 31

32

WIND AND SOLAR HAVE BALANCED RISK AND RETURNS

Attribute Wind Risk Solar Risk Hydro Risk

Resource Variability

Development

OpEx / CapEx

Levelized Cost of Energy

ULATIRR 8.5 – 9.5% 7.0 – 7.5% 7.5 – 8.0%

27

EXPAND OVERALL PORTFOLIO TO 2,500 MW + BY 2019

On Shore Wind: Expand current 656 MW portfolio to 1,600 MW Pipeline of 6 contracted projects will grow wind to 1,175MW Greenfield development in U.S. and Canada Acquire development opportunities

Utility Scale Solar: Increase solar portfolio from 10MW to 300MW Greenfield development in U.S. market Secure portfolio of utility scale development opportunities

33

GenerationCapacity (MW)

2,500

1,100

Jeff NormanVice President, Business Development

GENERATION

28

NORTH AMERICAN WIND MARKET CURRENT STATUS

35CANWEA, Wind Energy Markets: Installed Capacity

AWEA, U.S. Wind Industry Annual Market Report, Year Ending 2013AWEA, U.S. Wind Industry Third Quarter 2014 Market Report

NORTH AMERICAN SOLAR MARKET CURRENT STATUS

36CANSIA: 2013 Solar ReportNREL: 2012 Renewable Energy Data Book

29

DEVELOPMENT TEAM

37

Organized for Maximum Efficiency

Origination

Development

Construction

5 FTEs

10 FTEs

20 FTEs

SEIA, 2014

EFFICIENT GROWTH

38

AlgonquinFinancial Investors

RiskAdjusted Returns

Project Status

High

LowEarly

DevelopmentConstruction OperatingLate

Development

30

39

CURRENT DEVELOPMENT CAMPAIGN FOCUS

Strategic Campaigns Southeast US WindQF Solar

Regional CampaignsOntario Wind & Solar Saskatchewan WindNevada Solar

DEVELOPMENT PIPELINE

40

Project Status CapEx EBITDAMorse, SK Construction $81 Million $9.9 million

Bakersfield I, CA Construction $66 Million* $4.2 million

Bakersfield II, CA Construction $30 Million* $1.8 million

Odell, MN Construction $362 Million* $28 million

Val Eo, QC Development $70 Million $6.9 million

Amherst, CA Development $260 Million $30.4 million

Chaplin, SK Development $340 Million $35 million

Total $1,209 Million $116.2 Million

Bakersfield Solar Bakersfield SolarMorse Wind

* CapEx prior to contribution from tax equity investor

31

DEVELOPMENT PIPELINE

41

OdellOdell

ChaplinChaplin

MorseMorseVal EoVal Eo

Cornwall Solar

Cornwall Solar

SaintDamase

SaintDamase

Amherst Island

Amherst Island

BakersfieldII

BakersfieldII

Origination

Development

Construction

Operation

RECENTLY COMPLETED CONSTRUCTION – SAINT DAMASE

42

Hydro Quebec 20 year off take agreement Final Capital Cost = $49 million (net of CRCE) All 10 Enercon E-92 2.35 MW turbines

commissioned and operating Expected annual EBITDA $6.4 million COD Q4 2014 Seasonality:

Q1: 30% Q2: 19% Q3: 20% Q4: 31%

St. Damase Wind: 24 MW

QC

32

UPDATE ON CONSTRUCTION STATUS – MORSE

43

Morse Wind: 23 MW

SaskPower 20 year off take agreement Final Capital Cost = $81 million Roads and foundations complete Expected annual EBITDA $9.9 million COD Q1 2015 Seasonality:

Q1: 28% Q2: 24% Q3: 19% Q4: 29%

SK

UPDATE ON CONSTRUCTION STATUS – BAKERSFIELD I

44

Bakersfield I Solar: 20 MW AC

PG&E 20 year off-take agreement Final Capital Cost = $66 million / $40 million (net

of Tax Equity) 75% of panels installed Expected annual EBITDA $4.2 million COD Q1 2015 Seasonality:

Q1: 12% Q2: 33% Q3: 43% Q4: 12%

CA

33

UPDATE ON CONSTRUCTION STATUS – BAKERSFIELD II

45

Bakersfield II Solar: 10 MW AC

CA

SCE 20 year off-take agreement Capital Cost = $30 million / $18 million (net of

Tax Equity) Expected annual EBITDA $1.8 million COD Q1 2016 Seasonality:

Q1: 9% Q2: 36% Q3: 47% Q4: 8%

UPDATE ON CONSTRUCTION STATUS – ODELL

46

Odell Wind: 200 MW

MN

Sources Of Capital

Tax Equity $198

Equity $84

Bonds $80

Total $362

Northern States Power 20 year off-take agreement

46.9% P50, 821.7 GWh/year. CapEx = $362 million / $164 million (net of Tax

Equity) Expected annual EBITDA $28 million COD Q4 2015 Seasonality:

Q1: 31% Q2: 25% Q3: 13% Q4: 31%

34

UPDATE ON DEVELOPMENT STATUS – VAL-ÉO

47

Off-take Agreement Hydro Quebec, 20 years

Resource Analysis Data from four 60m towers (2006 – 2010) Additional tower installed September 2014. Data from SODAR (2012)

Permitting Status Decree from Environment Ministry expected

December 2014 Certificate of Authorization expected Q1 2015

Construction CapEx $70 million (prior to CRCE) / $52

million with CRCE COD Q4 2015

Val Éo Wind: 24 MW

QC

UPDATE ON DEVELOPMENT STATUS – AMHERST

48

Off-take Agreement Ontario Power Authority, 20 years

Resource Analysis 2005 – Present, including: Over one year of 100m data 8 months of LiDAR

Permitting Status REA expected in Jan/Feb 2015 if technical

changes are pursuedConstruction CapEx $260 million COD Q3/Q4 2016, based on expected ERT

process

Amherst Island Wind: 75 MW

ON

35

UPDATE ON DEVELOPMENT STATUS – CHAPLIN

49

Chaplin Wind: 177 MW

SK

Off-take Agreement SaskPower, 25 years

Resource Analysis May 2009 – Present Two additional towers added in 2014

Permitting Status Final EA package submission Q4 2014

Construction CapEx $340 million COD Q4 2016

Todd MooneyVice President, Finance & Administration

GENERATION

36

CAPEX DRIVES EBITDA GROWTH

51

-

200

400

600

800

1,000

1,200

1,400

2014 2015 2016 2017 2018

$ M

illio

ns

Cumulative CAPEX10.1

9.4

8.88.6 8.4

6.0

7.0

8.0

9.0

10.0

11.0

-

50

100

150

200

250

300

350

400

2014 2015 2016 2017 2018

$ M

illio

ns

EBITDA

EBITDA EV:EBITDA

Hydro23%

Solar3%

Thermal8%

Wind66%

2014 EBITDA ‐ $160M* 

52

EXPECTED EBITDA MIX: 2014 – 2018

Hydro11% Solar

4%

Thermal4%

Wind81%

2018 EBITDA ~ $345M

Growth Driver is Wind: 81% of EBITDA by 2018

* Consensus Estimate

Investment delivers significant EBITDA growth

37

IL47%

MB24%

TX18%

PA8%

SK3%

53

WIND – GEOGRAPHIC DIVERSIFICATION

Geographic diversification of wind almost doubles by 2018

IL25%

MB10%

TX10%PA

5%

SK21%

ON13%

MN11%

QC5%

2018 EBITDA - WIND

2014 EBITDA - WIND

54

2015 EBITDA SEASONALITY

2% 2% 2% 1%1% 2% 2% 2%5%

5% 3% 5%

20% 17%

12%

21%

0%

5%

10%

15%

20%

25%

30%

Q1 Q2 Q3 Q4

% o

f Ann

ual E

BIT

DA

Solar Natural Gas Hydro Wind

38

Solar HLBV income is

recognized over the first 5 years of the project

For Bakersfield this represents approximately $18 million from 2015 to 2019

55

TAX EQUITY - HLBV INCOME

Wind

Yr 1 Yr 2 Yr 3 Yr 4 Yr 5 Yr 6 Yr 7 Yr 8 Yr 9 Yr 10

HLBV Income ‐ Cumulative

Yr 1 Yr 2 Yr 3 Yr 4 Yr 5 Yr 6 Yr 7 Yr 8 Yr 9 Yr 10

Tax Equity Investment Balance

Years 1‐5: MACRS and PTC

Years 6‐10: Cash and PTC

2015 IN BRIEF

56

Investment

Increased Diversification

Value Accretion

Q1 COD Projects Morse, Bakersfield I

Construction Projects Odell, Bakersfield II

Development Projects Amherst, Val Éo, Chaplin

39

SUMMARY

GENERATION KEY MESSAGES

58

Existing $500 million portfolio is:

proceeding as planned, on time, on budget

Projects are EPS and FFOPS accretive

Continue to find accretive opportunities

Increased focus on 2 modalities

On Shore Wind,

Solar – Utility scale

Portfolio diversification is increasing overall

resource certainty

40

QUESTIONSGeneration

INVESTOR DAY2014

Distribution

FOCUSED GROWTH

41

David PasiekaPresidentDistribution

Peter EichlerDirector, Strategic InitiativesDistribution

Gerald TremblayVice President, Finance & AdministrationDistribution

DISTRIBUTION

David PasiekaPresident

42

63

AGENDA

Market dynamics State prosperity ROE trends Achieving returns Growth strategies Financial summary

Abundance of “Made in America” natural gas

Aging infrastructure creates investment opportunity

Cost of capital facilitates M&A activity

Customer demand being influenced by efficiency programs

64

NORTH AMERICAN UTILITY DYNAMICS

Dynamics create distribution opportunities

43

National utility footprint Diversified by commodity

and regulatory jurisdiction Opportunities for continued

investment Delivered on our growth

commitments

65

OUR DISTRIBUTION BUSINESS CONTINUES TO EVOLVE

U.S. utility sector provides a robust opportunity for investment

Actual Numbers

IMPROVING ECONOMIC CONDITIONS IN OPERATING STATES

66

State diversity reduces risk in our distribution portfolio

7.7%7.1%

6.4%5.7%

Projected Numbers Source: SNL

42,000

44,000

46,000

48,000

50,000

2011 2012 2013 2014 2015 2016 2017 2018 2019

Total Housing Units ('000s)

44

ROE AWARD TRENDS

67

ROE’s are leveling out between 9-10% across modalities

 ‐

 2.0

 4.0

 6.0

 8.0

 10.0

 12.0

 14.0

 16.0Average U.S. Utility ROE (%)

REGULATORY MECHANISMS STRATEGICALLY IMPORTANT

68

Mechanisms increase the opportunity to achieve authorized ROE’s

Mechanism AR AZ CA GA IL MA MO MT NH

DecouplingMechanism

MemorandumAccounts

Commodity Pass Through

AcceleratedRecovery

New in 2014

45

Decentralized model allows for local focus on the things that matter: Rate case outcomes Growth initiatives Stakeholder relations Customers engagement Community presence

69

DISTRIBUTION OPERATING PHILOSOPHY

Centralized strategy executed locally

Original 2009 “orphan” – closed 2011 First rate case in 2012:

ROE of 9.89% with 52% equity thickness Rate decoupling Future capital mechanism

Resulted in: Ability to deploy more capital Lower risk Higher returns Transmission and Generation

Bonus: Customer satisfaction and system reliability

70

CALIFORNIA – A SUCCESS STORY

Regulator relationship enhanced our ability to acquire Park Water

46

Acquisition criteria Accretive Attractive regulatory Favourable demographics Opportunity to invest

74,000 customers in Montana and California

$327 million purchase price Closing in 2015

71

PARK WATER ACQUISITION

Our competitive cost of capital allows us to acquire and still be accretive

DISTRIBUTION

Peter EichlerDirector, Strategic Initiatives

47

Acquisition growth Line of sight to $100 million investment Supportive regulatory jurisdictions and demographics Distribution tuck-ins $360 million Park Water acquisition - 2015

UTILITY GROWTH STRATEGY OVERVIEW

73

System Improvements

Customer Growth Acquisitions

$1.1 billion of focused investment opportunities through 2018

System improvements Rate base investments

with reduced lag Minimize rate impacts

Customer growth “On Network” and “Off

Network”

System improvements and customer growth represent $740 million in investment

ORGANIC GROWTH – SYSTEM IMPROVEMENTS

$740 million of investment opportunity through 2018 Not all rate base investments are created equal

Focused on investments that minimize regulatory lag Investments that create efficiencies (i.e. CapEx in place of OpEx) Targeted infrastructure with predetermined rate treatment

Approach ensures customer affordability without any premium

74

Nearly 80% of 2015-2018 distribution CapEx has recovery commencement in less than 12 months

Regulatory LagType of Investment Immediate <6 months <12 months <18 monthsTargeted InfrastructureEfficiency ImprovementGrowthSafetyOther System Improvements

48

SYSTEM IMPROVEMENTS – TARGETED INFRASTRUCTURE

Targeted infrastructure programs allow for replacement of: Gas pipe (MA, MO, NH, GA) Water and sewer infrastructure

(AZ) Electric projects above $4 million

(CA)

Recovery is granted through pre-authorized surcharge mechanisms

Allow returns to be realized immediately at most recently authorized ROEs

75

Over $90 million in targeted infrastructure investment through 2018 with no regulatory lag

$0

$5

$10

$15

$20

$25

$30

$35

$ m

illio

ns

Targeted Replacement Programs

2015 2016 2017 2018

ORGANIC GROWTH – CUSTOMER GROWTH

“On Network” growth Target incremental customers by

connecting customers on the distribution system

Expansion of current distribution systems to reach 5,000 new customers per year

“Off Network” growth Use of Compressed Natural Gas

or Liquefied Natural Gas to reach customers where no pipelines exist

Potential for 10,000 new connections in north-east

76

Organic growth increases customer and investment base without premiums

49

ORGANIC GROWTH – CUSTOMER GROWTH EXAMPLE

Virtual pipelines Seek out large use customers and clusters of smaller customers for

delivered natural gas Typically requires load of 50,000 dth and up to be economic

Mother station constructed on distribution gas system Increases throughput on the distribution utility

Natural gas delivered by truck to customer(s) site

77

Clusters of new customers create “Satellite LDCs”

ACQUISITION GROWTH

Strong M&A market persists Low cost of capital Economies of scale M&A as a way to deliver growth

Target size Average deal size in Q3 was

nearly $1 billion APUC capable of completing

larger transactions that are accretive

Focus on accretion Cost of capital advantages Allows transactions with larger

rate base premiums to be completed

78

$-

$5,000

$10,000

$15,000

$20,000

$25,000

$30,000

$35,000

$40,000

Q3 2013 Q4 2014 Q1 2014 Q2 2014 Q3 2014

Aggregate Transaction Value (USD million)

$4,606

$10,329

$4,385

$34,869

$11,089

Source:PwC Q3’14 Power & Utilities M&A Report

50

DISTRIBUTION

Gerald TremblayVice President, Finance & Administration

Authorized weighted ROE of 9.9%

Earnings to reflect rate filings:

Normalized weather

80

2015 EBITDA MIX

Water 19%

Electric22%

Gas 59%

State Rate Request Expected GA US $3.9M Q1 2015MO US $7.6M Q1 2015IL US $5.7M Q1 2015

AR US $2.5M Q2 2015NH US $16.1M Q3 2015

Total US $35.8M

51

81

2015 EBITDA SEASONALITY

74% of gas commodity Q1 and Q4

38% of EBITDA in Q1

Electric/water even across quarters

4% 5% 5% 5%

6% 5% 6% 5%

29%

11% 5%

15%

0%

5%

10%

15%

20%

25%

30%

35%

40%

45%

Q1 Q2 Q3 Q4

Water Electric Gas

82

DECOUPLING REDUCES VOLUMETRIC RISK

Reducing our volumetric risk

Decoupling 63% across the portfolio

Predictable earnings across all commodities

66%60% 64%

Gas Electric Water/Wastewater

Decoupling by Commodity as a % of Net Revenue

52

Water32%

Electric21%

Gas47%

2018 EBITDA ~ $284 million

83

EXPECTED EBITDA MIX: 2014 - 2018

*Consensus estimate

Water19%

Electric25%

Gas56%

2014 EBITDA - $159 million*

84

CAPITAL EXPENDITURES

2015-2018 CapEx spend over $1.1 billion Major projects:

Calpeco Solar LPSCO plant expansion Pipeline replacements System improvements New customer growth

Capital investment results in 79% increase to earnings from 2014

CAGR increase of 16% Distribution EV/EBITDA of ~ 7x

Cumulative CapEx EBITDA

0

200

400

600

800

1,000

1,200

1,400

2014 2015 2016 2017 2018

$ M

illio

ns

Existing Assets Park Water

-

50

100

150

200

250

300

2014 2015 2016 2017 2018

$ M

illio

ns

53

TEST YEAR RATE FILINGS

85

2015 NH, GA, AZ, TX

2016 NH, GA, AR, AZ

2017 CA, GA, MO, IL

2018 NH, MA, GA

SUMMARY

54

DISTRIBUTION: FOCUSED GROWTH

87

Results in $125 million of additional run rate EBITDA by 2018

$1.1 billion program to capitalize on utility dynamics

Focused growth System improvements and

customer growth $740 million from 2015 -

2018 Acquisitions Park Water - $360 million

QUESTIONSDistribution

55

INVESTOR DAY2014

Transmission

FOCUSED GROWTH

Ian RobertsonChief Executive OfficerAlgonquin Power & Utilities Corp.

Dick LeehrPresident, Pipelines & TransmissionTransmission

56

Ian RobertsonChief Executive OfficerAlgonquin Power & Utilities Corp.

TRANSMISSION

AGENDA

Rationale for sector Transmission investment strategy U.S. electric transmission market dynamics Electric transmission initiatives Natural gas pipeline market dynamics Transmission market focus Partnership with Kinder Morgan

92

57

RATIONALE FOR SECTOR

93

Strategic alignment

Asset alignment

Business and regulatory alignment

Operational alignment

LIBERTY INVESTMENT STRATEGY

94

Leverage our utility footprint

Growth through development

$450M portfolio CapEx

58

US ELECTRIC TRANSMISSION MARKET DYNAMICS

Socialized asset business model FERC ROE >10% Non-volumetric business model

FERC Order 1000 Incumbent interstate transmission

advantage downplayed Intended to create more transparent

process for selection of transmission initiatives

Focus near our existing utility footprint to leverage transmission opportunities California, New Hampshire Northern Ontario

95

96

TRANSMISSION OPPORTUNITIES

Dixie Valley 214 mile 230KV line 400 MW capacity in Nevada

CALPECO 625-650 625/650 Project Upgrade 24 miles

of 60 kV to 120kV broken into 3 phases

619 Portola 50 mile 60KV line Could be

connected to CAISO

NWC Project 300 mile 230 KV line Link to Eldorado Valley &

Bishop

1

2

4

3

59

Dick LeehrPresident, Pipelines & Transmission

TRANSMISSION

SHALE GAS - FOUNDATION FUEL FOR NORTH AMERICA

98

2014

60

Natural gas pipelines serve a variety of loads for North America Utilities, generation,

industrial feedstock, commercial, LNG exports, producers - all drive demand

Pipeline business model FERC or state regulated Long term bilateral

contracts with creditworthy counterparties

99

NATURAL GAS PIPELINE ENVIRONMENT

National transmission picture $800 billion of investment

opportunity Driven by shale revolution

from traditional sources

Regional picture -Northeast Sits atop Utica/Marcellus

shale deposits Capacity constraints fueling

pipeline development Demand will accommodate

several projects

100

NATURAL GAS PIPELINE ENVIRONMENT

61

WHY THE NORTHEAST FOCUS

101Source: Bentek Presentation  ‐ November 2014

Northeast will account for 30% of U.S. production by 2019

NORTHEAST ENERGY DIRECT PROJECT: MARKET PATH

102

PROJECT DETAILS 30”/36” line, 176 miles through NY, MA, NH Brings 0.8 Bcf/d – 2.2 Bcf/d of capacity In service November 2018 Serves New England LDC’s, gas fired

generation markets with additional franchising opportunities in NH and MA.

PROJECT BENEFITS Brings low cost Marcellus/Utica supply

to the Northeast and Canada Only cross regional project Lowers energy costs for the region Platform for regional economic growth

62

ATTRACTIVE SUPPLY ALTERNATIVE

103

Subscribed for 115,000 Dth/day capacity on NED

New capacity will lower gas prices in the entire region

Provides reliable second route for NH gas delivery at Concord

Best priced option for securing economic shale supply

Opportunity to expand regulated footprint within NH via proposed alternative route

Provides 10 years of forecasted capacity for the utility

$83

$120$126

$45$50$60

$103

$30

$0

$20

$40

$60

$80

$100

$120

$140

Winter2012/2013

Winter2013/2014

Winter2014/2015

Winter2018/2019(Forecast)

Avg. Monthly NH Residential Customer Commodity Cost Gas

Electric

PARTNERSHIP FOR NORTHEAST ENERGY DIRECT

104

Partnering with Kinder Morgan for development

Initial partnership participation of 2.5%; option to subscribe for additional 7.5%

Capital investment up to U.S. $400M

Base ROE accretive to earnings

Additional expansion opportunities

63

SUMMARY

SUMMARY – TRANSMISSION

A logical investment

Consistent asset, business and risk profile

Growing investment pipeline

Partnership with global leader for Northeast Energy Direct

106

64

QUESTIONSTransmission

108

2014 INVESTOR MORNING SUMMARY

Commitment to strong capital structureConservative balance sheet leading with equity

Able to deliver financial resultsEBITDA growth consistent with targetsRobust EPS/FFOPS growth supporting dividend

$2.8B focused, accretive growthGeneration: $1.2B - contracted solar and windDistribution: $1.1B - organic and acquisition growthTransmission: $0.5B - gas and electric transmission

65

APPENDIX

* Based on achieving placed-in-service (mechanical completion) in 2014

SIMPLIFIED HLBV ESTIMATION

110

Simple Regression: y = mx + bHLBV Income = m x Production + b

2015 2016 2017

MK, SN, SRMK,

SN, SR OdellMK,

SN, SR OdellProduction (MWh) “x” 1,309,300 1,309,300 810,800* 1,309,300 810,800*

Slope ($/MWh) “m” 0.032 0.033 0.076 0.033 0.076

Constant ($) “b” ($4,200)/ Quarter

($3,700)/ Quarter

($12,000) / Quarter

($3,300)/ Quarter

($12,000) / Quarter

Wind

Solar HLBV income is recognized over the first 5 years of the project; for Bakersfield this is approx. $18 million in total

2015 2016 2017 2018 2019HLBV Income* 15% 22% 22% 21% 20%

66

Authorized weighted ROE of 9.9%

Expected Net Revenue: $49.47/GW-hr $9.89/Dcth $3.85/1000 Gallons Sold $11.74/1000 Gallons Treated Rates do not include rate

increases for 2015 with exception of EN with expected interim rates of $7.4M

Normalized weather

111

2015 EBITDA - DISTRIBUTION

Water 19%

Electric22%

Gas59%

2015 EBITDA Mix

67