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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
1
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.
4
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
5
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.
9
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.
10
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
12
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
25
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
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