Generation.
Transmission.
Distribution.
Investor Day - November 25, 2014
Contents
Agenda
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 Morning
Tuesday, November 25, 2014
8:00 – 8:30 a.m.
Registration
Coffee and Continental Breakfast
8:30 – 8:35 a.m.
Welcome and Opening Remarks
8:35 – 9:30 a.m.
Algonquin Power & Utilities
Executive Panel
9:30 – 10:30 a.m.
Kelly Castledine, Director, Investor Relations
Ian Robertson, CEO
Chris Jarratt, Vice Chair
David Bronicheski, CFO
Generation
Strategy and Operations
Business Development
Financials
Mike Snow, President
Jeff Norman, Vice President, Business Development
Todd Mooney, Vice President, Finance & Administration
10:30 – 10:45 a.m.
Break
10:45 – 11:45 p.m.
Distribution
Strategy and Operations
Distribution Growth
Financials
David Pasieka, President
Peter Eichler, Director, Strategic Initiatives
Gerald Tremblay, Vice President, Finance & Administration
Transmission
Strategy
Transmission Opportunities
Ian Robertson, CEO
Dick Leehr, President, Pipelines & Transmission
11:45 – 12:15 p.m.
12:30 – 1:00 p.m.
Lunch Presentation
Energy Storage:
Energy opportunities in an
evolving utility landscape
Charlie Ashman, Vice President, Technology
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 forwardlooking 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 of
ability to generate cash from operations. APUC uses these calculations to monitor the amount
of cash generated by APUC as compared to the amount of dividends paid by APUC. APUC
uses Adjusted EBITDA to assess the operating performance of APUC without the effects of (as
applicable): depreciation and amortization expense, income tax expense or recoveries,
acquisition costs, litigation expenses, interest expense, 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
2014
2013
$
Revenue
684.2
1
$
470.0
Year ended
December 31
2013
2012
$
675.3
$
348.8
206.2
159.6
226.9
88.1
96.3
70.5
98.9
63.0
140.6
107.1
153.5
66.8
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
57.5
50.8
68.3
50.2
Adjusted EBITDA
Cash provided by operating activities
Adjusted funds from operations1
Net earnings attributable to shareholders
Shareholders
Per share
Basic net earnings from continuing
$
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
$
0.18
$
0.02
$
0.07
$
0.09
$
0.46
$
0.35
$
0.48
$
0.40
$
0.64
$
0.51
$
0.72
$
0.42
$
0.27
$
0.25
$
0.33
$
0.30
operations
Diluted net earnings
Cash provided by Operating Activities
Adjusted funds from operations
1,2
Dividends declared to Shareholders
Total Assets
2
$ 3,808.5
$ 3,156.4
$ 3,472.6
$ 2,779.0
1,413.5
1,092.0
1,255.6
770.8
3
Total Liabilities (includes current portion)
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-forprofits. 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.
11
INVESTOR DAY
2014
Generation Transmission Distribution
FOCUSED GROWTH
Ian Robertson
Chief Executive Officer
EXECUTIVE PANEL
Chris Jarratt
Vice Chair
David Bronicheski
Chief Financial Officer
12
VISION
Our Vision
Capital
Markets
Impact
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
3
13
WHAT HAS CHANGED?
5
ALGONQUIN POWER & UTILITIES
A GROWTH FOCUSED GENERATION, TRANSMISSON AND
DISTRIBUTION UTILITY COMPANY
G E N E R AT I O N
Attractive and growing
returns from renewable
power generation portfolio
TRANSMISSION
DISTRIBUTION
Attractive risk-adjusted
returns from regulated
transmission utility assets
Predictable and growing
earnings as a national US
distribution utility
Non-regulated
Federal /State regulated
State regulated
50% of 2014 EBITDA
50% of 2014 EBITDA
25% Canada / 75% US
Natural gas pipelines and
electrical transmission
100% US
$1.7 billion investment in
1,100 MW gross installed
capacity
North American focus
$450 million investment
potential through
development pipeline
$1.8 billion utility assets
480,000 connections
$1.1 billion investment
potential through
acquisition and organic
CAPEX pipeline
$1.2 billion investment
potential through 500MW
development pipeline
6
14
EVOLUTION OF THE BOARD OF DIRECTORS
Masheed Saidi
Former Chief Operating Officer and Executive Vice
President of U.S. Transmission for National Grid USA.
Dilek Samil
Former Executive Vice President and Chief Operating
Officer of NV Energy
7
15
2014 BY THE NUMBERS
DELIVERED LTM
TARGET
~15%
GROWTH IN ASSETS
21%
~15%
GROWTH IN ADJUSTED EBITDA
29%
7‐10%
GROWTH IN ADJUSTED NET
EARNINGS
31%
>10%
TOTAL SHAREHOLDER
RETURN
46%
9
TOTAL SHAREHOLDER RETURN
SHAREHOLDER VALUE TRIPLED SINCE 2008
TOTAL RETURN PERFORMANCE
Algonquin Power & Utilities S&P/TSX Composite Index
S&P/TSX Utilities Index
Value of $100 invested in 2008
16
10
COST OF CAPITAL
8.00%
7.50%
7.00%
6.50%
6.00%
5.50%
5.00%
4.50%
4.00%
AQN
Canadian IPP
Peers
U.S. Yield
Cos.
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
FORECAST GROWTH IN ASSETS AND EBITDA
15% Growth Target
vs. Planned Net
Asset Growth
15% Growth Target
vs. Expected
EBITDA from
Planned Growth
12
17
ADMINISTRATION COSTS
$35,000
$30,000
25%
22.22%
20%
$25,000
$20,000
10.36%
$15,000
15%
9.17%
$10,000
5%
$5,000
$0
10%
2012
2013
Administration expenses
As a percent of EBITDA
2014
0%
Centralization of services
13
18
Value of $100 invested in January 2009
EXECUTIVE COMPENSATION VS. PERFORMANCE
500
400
300
200
100
0
1-Jan-09
1-Jan-10
1-Jan-11
1-Jan-12
1-Jan-13
1-Jan-14
15
SOURCES & USES OF CAPITAL
Uses of Capital
Sources of Capital
Common Equity
Preferred Shares
Park Water
Tax Equity
Cash from Ops
Odell Wind
Debt
Distribution Capital
Generation Capital
16
19
CAPITAL STRUCTURE
September 30, 2014
000's
Long term liabilities
Preferred shares
Equity
Total capitalization
1,413,473
46.7%
213,807
7.1%
1,400,261
46.3%
3,027,541
100.0%
S&P: BBB
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
A GROWTH FOCUSED GENERATION, DISTRIBUTION AND
TRANSMISSION UTILITY COMPANY
G E N E R AT I O N
Attractive and
growing returns
from renewable
power generation
portfolio
TRANSMISSION
DISTRIBUTION
Attractive riskadjusted returns
from regulated
transmission
utility assets
Predictable and
growing earnings
as a national US
distribution
utility
19
QUESTIONS
21
INVESTOR DAY
2014
Generation
FOCUSED GROWTH
Mike Snow
President
Generation
Jeff Norman
Vice President, Business Development
Generation
Todd Mooney
Vice President, Finance & Administration
Generation
22
GENERATION
Mike Snow
President
AGENDA
Value creation
Market dynamics
Portfolio diversification
Generation strategy
Development plans
Financial indicators
24
23
PROVEN TRACK RECORD IN VALUE CREATION
Capital Efficiency Increasing with Growth
16.0
14.0
12.0
10.0
8.0
6.0
4.0
2.0
0.0
13.6x
2010
12.4x 12.3x
2011
2012
11.1x
2010 – 2013
• EBITDA growth from $67M $129M
• $600M capital spend across
five wind projects
• St. Leon II, Sandy Ridge,
Minonk, Senate, Shady Oaks
2013
25
DELIVERING 267 MW OF 2014 / 2015 ACCRETIVE PROJECTS
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 $1.28
COD: Q1 2015
COD: Q1 2015
COD: Q4 2015
26
24
WIND TECHNOLOGY POSITIVELY IMPACTS LCOE
LCOE ($/MWh)
Significant decline in LCOE in 5 years
160
140
120
100
80
60
40
20
0
$135
$124
$71 $70
$70
$37- $81
2009 2010 2011 2012 2013 2014
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
DECLINING SOLAR COSTS POSITIVELY IMPACT LCOE
Sustainable cost reductions achieved
Improved manufacturing efficiency
Lower cost materials
Panel redesign
Polysilicon / Wafer
2011 LCOE:
$157
$0.76/W
Secure LT wafer supply
Lower cost silicon
Supply diversification
2014 LCOE:
$72 - $86
$0.22/W
Cell
Module
$0.22/W
$0.33/W
Total
$1.31/W
Reduce cell to module
Reduce raw mat’l cost
power loss
Reduce raw mat’l usage
Reduce raw mat’l cost
Increase throughput
Redesign modules
$0.15/W
$0.16/W
$0.53/W
28
25
POSITIVE OUTLOOK FOR NORTH AMERICAN RENEWABLES
Wind & Solar Drive Renewable Growth
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
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
29
WIND DIVERSIFICATION IMPROVES PORTFOLIO CERTAINTY
Wind projects located in areas of greater wind speed certainty
Less wind
speed certainty
Greater wind
speed certainty
Algonquin Wind Projects
26
30
WIND DIVERSIFICATION IMPROVES PORTFOLIO CERTAINTY
Variability of
production of
individual
projects
Portfolio effect improves
production stability
P90 portfolio energy is
5.6% > P90 13 Sites
Further diversification:
Variability as a
portfolio
5 technologies
8 creditworthy offtakers
Seasonality
60
70
80
90
100
110
120
130
140
31
31
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%
32
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
2,500
1,100
Generation
Capacity (MW)
33
GENERATION
Jeff Norman
Vice President, Business Development
28
NORTH AMERICAN WIND MARKET CURRENT STATUS
CANWEA, Wind Energy Markets: Installed Capacity
AWEA, U.S. Wind Industry Annual Market Report, Year Ending 2013
AWEA, U.S. Wind Industry Third Quarter 2014 Market Report
35
NORTH AMERICAN SOLAR MARKET CURRENT STATUS
CANSIA: 2013 Solar Report
NREL: 2012 Renewable Energy Data Book
29
36
DEVELOPMENT TEAM
Organized for Maximum Efficiency
Origination
5 FTEs
Development
10 FTEs
Construction
20 FTEs
SEIA, 2014
37
EFFICIENT GROWTH
High
Algonquin
Financial Investors
Risk
Adjusted
Returns
Low
Early
Development
Late
Development
Construction
Operating
Project Status
38
30
CURRENT DEVELOPMENT CAMPAIGN FOCUS
Strategic Campaigns
Southeast US Wind
QF Solar
Regional Campaigns
Ontario Wind & Solar
Saskatchewan Wind
Nevada Solar
39
DEVELOPMENT PIPELINE
Project
Status
CapEx
Morse, 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
$1,209 Million
$116.2 Million
Total
Morse Wind
EBITDA
Bakersfield Solar
Bakersfield Solar
* CapEx prior to contribution from tax equity investor
31
40
DEVELOPMENT PIPELINE
Origination
Bakersfield
II
Odell
Amherst
Island
Development
Morse
Val Eo
Construction
Operation
Chaplin
Cornwal
l Solar
Saint
Damase
41
RECENTLY COMPLETED CONSTRUCTION – SAINT DAMASE
St. Damase Wind: 24 MW
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%
QC
42
32
UPDATE ON CONSTRUCTION STATUS – MORSE
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
43
UPDATE ON CONSTRUCTION STATUS – BAKERSFIELD I
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
44
33
UPDATE ON CONSTRUCTION STATUS – BAKERSFIELD II
Bakersfield II Solar: 10 MW AC
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%
CA
45
UPDATE ON CONSTRUCTION STATUS – ODELL
Odell Wind: 200 MW
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%
MN
Sources Of Capital
Tax Equity
$198
Equity
$84
Bonds
$80
Total
$362
46
34
UPDATE ON DEVELOPMENT STATUS – VAL-ÉO
Val Éo Wind: 24 MW
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)
QC
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
47
UPDATE ON DEVELOPMENT STATUS – AMHERST
Amherst Island Wind: 75 MW
Off-take Agreement
Ontario Power Authority, 20 years
ON
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 pursued
Construction
CapEx $260 million
COD Q3/Q4 2016, based on expected ERT
process
48
35
UPDATE ON DEVELOPMENT STATUS – CHAPLIN
Chaplin Wind: 177 MW
Off-take Agreement
SaskPower, 25 years
Resource Analysis
May 2009 – Present
Two additional towers added in 2014
SK
Permitting Status
Final EA package submission Q4 2014
Construction
CapEx $340 million
COD Q4 2016
49
GENERATION
Todd Mooney
Vice President, Finance & Administration
36
CAPEX DRIVES EBITDA GROWTH
1,400
Cumulative CAPEX
350
1,200
300
$ Millions
$ Millions
1,000
800
600
10.0
9.4
8.8
8.6
200
8.4
200
50
-
9.0
8.0
150
100
2014 2015 2016 2017 2018
11.0
10.1
250
400
-
EBITDA
400
7.0
2014 2015 2016 2017 2018
EBITDA
6.0
EV:EBITDA
51
EXPECTED EBITDA MIX: 2014 – 2018
Investment delivers significant EBITDA growth
2018 EBITDA ~ $345M
2014 EBITDA ‐ $160M* Hydro
11%
Thermal
4%
Hydro
23%
Wind
66%
Solar
4%
Solar
3%
Thermal
8%
Wind
81%
Growth Driver is Wind: 81% of EBITDA by 2018
* Consensus Estimate
52
37
WIND – GEOGRAPHIC DIVERSIFICATION
2018 EBITDA - WIND
2014 EBITDA - WIND
PA
8%
TX
18%
SK
3%
MN
11%
QC
5%
IL
25%
ON
13%
IL
47%
MB
10%
MB
24%
SK
21%
PA
5%
TX
10%
Geographic diversification of wind almost doubles by 2018
53
2015 EBITDA SEASONALITY
30%
% of Annual EBITDA
25%
20%
15%
20%
21%
17%
12%
10%
5%
3%
5%
1%
2%
2%
2%
2%
2%
2%
1%
Q1
Q2
Q3
Q4
5%
5%
0%
Solar
Natural Gas
Hydro
Wind
54
38
TAX EQUITY - HLBV INCOME
Wind
Solar
HLBV income is
recognized over the first
5 years of the project
For Bakersfield this
represents approximately
$18 million from 2015 to
2019
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
Yr 1
Yr 2
Yr 3
Yr 4
Yr 5
Yr 6
Yr 7
Yr 8
Yr 9
Yr 10
55
2015 IN BRIEF
Value Accretion
Increased Diversification
Investment
Q1 COD Projects
Morse, Bakersfield I
Construction Projects
Odell, Bakersfield II
Development Projects
Amherst, Val Éo, Chaplin
56
39
SUMMARY
GENERATION KEY MESSAGES
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
58
40
QUESTIONS
Generation
INVESTOR DAY
2014
Distribution
FOCUSED GROWTH
41
David Pasieka
President
Distribution
Peter Eichler
Director, Strategic Initiatives
Distribution
Gerald Tremblay
Vice President, Finance & Administration
Distribution
DISTRIBUTION
David Pasieka
President
42
AGENDA
Market dynamics
State prosperity
ROE trends
Achieving returns
Growth strategies
Financial summary
63
NORTH AMERICAN UTILITY DYNAMICS
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
Dynamics create distribution opportunities
64
43
OUR DISTRIBUTION BUSINESS CONTINUES TO EVOLVE
National utility footprint
Diversified by commodity
and regulatory jurisdiction
Opportunities for continued
investment
Delivered on our growth
commitments
U.S. utility sector provides a robust opportunity for
investment
65
IMPROVING ECONOMIC CONDITIONS IN OPERATING STATES
Total Housing Units ('000s)
50,000
48,000
7.7%
46,000
7.1%
6.4%
5.7%
44,000
42,000
2011
2012 2013 2014
Actual Numbers
2015 2016 2017
2018 2019
Projected Numbers
Source: SNL
State diversity reduces risk in our distribution portfolio
66
44
ROE AWARD TRENDS
Average U.S. Utility ROE (%)
16.0
14.0
12.0
10.0
8.0
6.0
4.0
2.0
‐
ROE’s are leveling out between 9-10% across modalities
67
REGULATORY MECHANISMS STRATEGICALLY IMPORTANT
Mechanism
AR
AZ
CA
GA
IL
MA
MO
MT
NH
Decoupling
Mechanism
Memorandum
Accounts
Commodity
Pass Through
Accelerated
Recovery
New in 2014
Mechanisms increase the opportunity to achieve
authorized ROE’s
45
68
DISTRIBUTION OPERATING PHILOSOPHY
Decentralized model allows
for local focus on the things
that matter:
Rate case outcomes
Growth initiatives
Stakeholder relations
Customers engagement
Community presence
Centralized strategy executed locally
69
CALIFORNIA – A SUCCESS STORY
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
Regulator relationship enhanced our ability to
acquire Park Water
46
70
PARK WATER ACQUISITION
Acquisition criteria
Accretive
Attractive regulatory
Favourable demographics
Opportunity to invest
74,000 customers in
Montana and California
$327 million purchase price
Closing in 2015
Our competitive cost of capital allows us to
acquire and still be accretive
71
DISTRIBUTION
Peter Eichler
Director, Strategic Initiatives
47
UTILITY GROWTH STRATEGY OVERVIEW
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
System Improvements
Customer Growth
Acquisitions
Acquisition growth
Line of sight to $100 million investment
Supportive regulatory jurisdictions and demographics
Distribution tuck-ins
$360 million Park Water acquisition - 2015
$1.1 billion of focused investment opportunities
through 2018
73
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
Type of Investment
Targeted Infrastructure
Efficiency Improvement
Growth
Safety
Other System Improvements
Immediate
Regulatory Lag
<6 months <12 months <18 months
Nearly 80% of 2015-2018 distribution CapEx has recovery
commencement in less than 12 months
48
74
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 preauthorized surcharge mechanisms
$ millions
Allow returns to be realized
immediately at most recently
authorized ROEs
Targeted Replacement Programs
$35
$30
$25
$20
$15
$10
$5
$0
2015
2016
2017
2018
Over $90 million in targeted infrastructure
investment through 2018 with no regulatory lag
75
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
Organic growth increases customer and investment
base without premiums
49
76
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
Clusters of new customers create “Satellite LDCs”
77
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
Aggregate Transaction Value
(USD million)
$40,000
$34,869
$35,000
$30,000
$25,000
$20,000
$15,000
$10,000
$5,000
$-
Cost of capital advantages
Allows transactions with larger
rate base premiums to be
completed
$11,089
$10,329
$4,606
Q3 2013
$4,385
Q4 2014
Q1 2014
Q2 2014
Q3 2014
Source:
PwC Q3’14 Power & Utilities M&A Report
78
50
DISTRIBUTION
Gerald Tremblay
Vice President, Finance & Administration
2015 EBITDA MIX
Water
19%
Gas 59%
Authorized weighted ROE
of 9.9%
Earnings to reflect rate
filings:
Electric
22%
State
Rate Request
Expected
GA
US $3.9M
Q1 2015
MO
US $7.6M
Q1 2015
IL
US $5.7M
Q1 2015
AR
US $2.5M
Q2 2015
NH
US $16.1M
Q3 2015
Total
US $35.8M
Normalized weather
80
51
2015 EBITDA SEASONALITY
45%
74% of gas commodity
Q1 and Q4
40%
35%
30%
38% of EBITDA in Q1
25%
29%
20%
15%
11%
15%
5%
10%
5%
0%
6%
5%
4%
5%
Q1
6%
Q2
Water
Electric
Electric/water even
across quarters
5%
5%
5%
Q3
Q4
Gas
81
DECOUPLING REDUCES VOLUMETRIC RISK
Decoupling by Commodity as a
% of Net Revenue
66%
60%
Reducing our volumetric
risk
Decoupling 63% across
the portfolio
64%
Predictable earnings
across all commodities
Gas
Electric
Water/Wastewater
82
52
EXPECTED EBITDA MIX: 2014 - 2018
2018 EBITDA ~ $284 million
2014 EBITDA - $159 million*
Water
19%
Gas
56%
Water
32%
Gas
47%
Electric
25%
Electric
21%
*Consensus estimate
83
CAPITAL EXPENDITURES
Cumulative CapEx
1,400
EBITDA
300
1,200
250
200
800
$ Millions
$ Millions
1,000
600
400
150
100
50
200
0
2014
2015
Existing Assets
2016
2017
2018
2014
2015
2016
2017
2018
Park Water
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
84
53
TEST YEAR RATE FILINGS
2015
NH, GA, AZ, TX
2016
NH, GA, AR, AZ
2017
CA, GA, MO, IL
2018
NH, MA, GA
85
SUMMARY
54
DISTRIBUTION: FOCUSED GROWTH
$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
Results in $125 million of additional run rate
EBITDA by 2018
87
QUESTIONS
Distribution
55
INVESTOR DAY
2014
Transmission
FOCUSED GROWTH
Ian Robertson
Chief Executive Officer
Algonquin Power & Utilities Corp.
Dick Leehr
President, Pipelines & Transmission
Transmission
56
TRANSMISSION
Ian Robertson
Chief Executive Officer
Algonquin Power & Utilities Corp.
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
Strategic alignment
Asset alignment
Business and regulatory
alignment
Operational alignment
93
LIBERTY INVESTMENT STRATEGY
Leverage our utility footprint
Growth through development
$450M portfolio CapEx
94
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
TRANSMISSION OPPORTUNITIES
1
CALPECO 625-650
625/650 Project
Upgrade 24 miles
of 60 kV to 120kV
broken into 3
phases
2
619 Portola
50 mile 60KV line
Could be
connected to
CAISO
3
NWC Project
4
Dixie Valley
300 mile 230 KV line
Link to Eldorado Valley &
Bishop
214 mile 230KV line
400 MW capacity in Nevada
96
59
TRANSMISSION
Dick Leehr
President, Pipelines & Transmission
SHALE GAS - FOUNDATION FUEL FOR NORTH AMERICA
2014
98
60
NATURAL GAS PIPELINE ENVIRONMENT
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
61
WHY THE NORTHEAST FOCUS
Northeast will account for 30% of U.S. production by 2019
101
Source: Bentek Presentation ‐ November 2014
NORTHEAST ENERGY DIRECT PROJECT: MARKET PATH
PROJECT DETAILS
30”/36” line, 176 miles through NY, MA, NH
Brings 0.8 Bcf/d – 2.2 Bcf/d of capacity
PROJECT BENEFITS
Brings low cost Marcellus/Utica supply
to the Northeast and Canada
In service November 2018
Only cross regional project
Serves New England LDC’s, gas fired
generation markets with additional
franchising opportunities in NH and MA.
Platform for regional economic growth
Lowers energy costs for the region
102
62
ATTRACTIVE SUPPLY ALTERNATIVE
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
Avg. Monthly NH Residential
Customer Commodity Cost
$140
$120
$120
$100
$80
$60
Gas
Electric
$126
$103
$83
$60
$50
$45
$40
$30
$20
$0
Provides 10 years of
forecasted capacity for the
utility
Winter
2012/2013
Winter
2013/2014
Winter
2014/2015
Winter
2018/2019
(Forecast)
103
PARTNERSHIP FOR NORTHEAST ENERGY DIRECT
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
104
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
QUESTIONS
Transmission
2014 INVESTOR MORNING SUMMARY
Commitment to strong capital structure
Conservative balance sheet leading with equity
Able to deliver financial results
EBITDA growth consistent with targets
Robust EPS/FFOPS growth supporting dividend
$2.8B focused, accretive growth
Generation: $1.2B - contracted solar and wind
Distribution:
$1.1B - organic and acquisition growth
Transmission: $0.5B - gas and electric transmission
108
65
APPENDIX
SIMPLIFIED HLBV ESTIMATION
Wind
Simple Regression:
y = mx + b
HLBV Income = m x Production + b
2015
2016
2017
MK, SN, SR
MK,
SN, SR
Odell
MK,
SN, SR
Odell
Production (MWh)
“x”
1,309,300
1,309,300
810,800*
1,309,300
810,800*
Slope ($/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
Solar
HLBV Income*
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
2019
15%
22%
22%
21%
20%
* Based on achieving placed-in-service (mechanical completion) in 2014
66
110
2015 EBITDA - DISTRIBUTION
2015 EBITDA Mix
Authorized weighted ROE
of 9.9%
Expected Net Revenue:
Water
19%
Gas
59%
Electric
22%
$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
67
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