Alberta’s future
energy mix:
exploring the
potential for
renewables
Issue: 3
February 2014
kpmg.ca
© 2014 KPMG LLP, a Canadian limited liability partnership and a member firm of the KPMG network of independent member firms affiliated with KPMG International Cooperative (“KPMG International”), a Swiss entity. All rights reserved.
KPMG invests in the industry through thought leadership papers and
journals, share forums and whitepapers on trends, opportunities and
challenges affecting the Canadian Power & Utilities sector.
Issue one, A New Era for Clean Energy in Canada, provided an update
on project finance market trends and commented on the prospects of
new power generation developments in British Columbia and the rest
of Canada.
Issue two, Wind Energy in Canada: Realizing the Opportunity,
examined wind financing activities given the significant activity in
the sector in the last 18 months and highlighted the next wave of
wind opportunities in the province of Québec.
In this issue we focus on Alberta’s future energy mix, by
discussing the opportunities that will arise for new electricity
generation in Alberta, the energy sources that will feature
most prominently and assess the potential for renewable
energy projects. We also analyze the complexities of the
Alberta market, the impact that power policy revisions may
have on investment in renewable energy and the issues
related to project financing in the province.
© 2014 KPMG LLP, a Canadian limited liability partnership and a member firm of the KPMG network of independent member firms affiliated with KPMG International Cooperative (“KPMG International”), a Swiss entity. All rights reserved.
Clean Energy Report | 01
Summary findings
Alberta is one of the few jurisdictions in Canada with significant
new generation requirements. However, with limited opportunities
for long-term contracts to support developments, new projects
need to rely on merchant prices to provide sufficient returns
and debt coverage. There is a growing consensus in industry
that increased demand and pending changes to existing policies
are converging to support significant generation investments in
Alberta, including new renewables.
Combination of significant load
growth and retirements creating
new generation requirements
Alberta’s oil sands industry continues
to drive new electricity demand. The
Alberta Electric System Operator
(AESO) estimates that peak demand
will hit 18,194 MW by 2032, a
significant increase on the 10,599 MW
peak demand in 2012. This represents a
compound annual growth rate (CAGR)
of almost 3% without considering
coal-fired plant retirements in excess
of 4,500 MW.1 This is significantly
more than the forecast US load CAGR
of 0.8% during the same period. 2 The
AESO estimates that 6,190 MW of new
effective electricity capacity will need
to be built in Alberta by 2022 to meet
demand and that 12,965 MW will need
to be installed by 2032. 3
Generation and load growth
driving transmission development
needs
It has been estimated that
approximately $13-$15 billion will be
invested in transmission assets in
Alberta in the next five to 10 years.
This investment requirement is
partly being driven by oil sands
developments in the northern parts of
the province and from the addition of
new generation planned to come into
service in transmission constrained
areas, both of which require an
upgraded system to connect to the
grid.
Gas to plug capacity gap in the
next five years
New combined cycle natural gas-fired
power plants, and to a lesser extent
some simple cycle peaking facilities,
are expected to be the preferred mode
of generation built to meet Alberta’s
supply gap in the next five years.
Gas plants currently remain attractive
due to the current and expected
future low price of natural gas and
the comparatively fewer restrictions
on site selection compared to other
jurisdictions. The AESO estimates that
gas-fired installed capacity will reach
over 11,000 MW in 2022, representing
53% of Alberta’s energy mix. In 2012
5,359 MW (representing about 40%
of the overall energy mix) of gas-fired
generating capacity was operational.4
The AESO predicts that new wind
capacity will make up the balance.
Alberta Electric System Operator, AESO 2012 Long-term Outlook Update (Calgary, AB: AESO, 2013)
US Energy Information Administration, Annual Energy Outlook 2013
1, 3, 4
2
© 2014 KPMG LLP, a Canadian limited liability partnership and a member firm of the KPMG network of independent member firms affiliated with KPMG International Cooperative (“KPMG International”), a Swiss entity. All rights reserved.
02 | Clean Energy Report
Economics for new wind projects
are challenging
Despite the recent rise in natural gas
prices, depressed pricing challenges
the economic case for wind energy.
Natural gas prices are expected to
average $3.48/GJ in 2014 and $3.50/
GJ in 2015, an increase on the 2012
average price ($2.28/GJ) but in line
with the average price in 2011 ($3.48/
GJ), according to Gas Alberta.5 Despite
a challenging pricing environment,
some major wind farms in Alberta have
made considerable progress in the
past 18 months by realizing value from
a California Renewable Energy Credit
(REC) measure. This measure, which is
no longer available, enabled some level
of debt financing to be added to the
projects’ capital structure.
New policies could mobilize
renewables investment
Both the Alberta and Federal
government are considering a series
of policy initiatives relating to carbon
emissions. The Federal government
released its Reduction of Carbon
Dioxide Emissions from Coal-fired
Generation of Electricity Regulations
in 2012, which is expected to be
effective in 2015. Provincially, while
the Alberta government has not yet
announced any formal policies, it
is expected to bolster the current
Specified Gas Emitters Regulation
in a way that will incentivize oil and
gas companies to offset their carbon
emissions through renewable energy
investments. In addition, the Alberta
government has committed to
implementing an alternative energy
framework that will encourage
investment in renewable energy
projects. New provincial policies are
expected to be announced in 2014.
Solar an option in Alberta
The solar industry feels that it is often
given short shrift when considering
Alberta’s future energy mix. However,
the province’s solar resource is 25%
better than Ontario’s and 30% better
than Germany’s, according to the
Canadian Solar Industries Association
(CanSIA).6 Despite this, virtually no
solar capacity is currently operating
in Alberta. If the province adopts
an attractive alternative energy
framework, solar would certainly
complement wind as it could generate
electricity during the intervals when
wind farms are not operating. This is
especially true given that the average
peak price is close to grid parity.
The bulk of a solar photovoltaic (PV)
generator’s margin will be made when
the power price moves above $80 per
MWh.
Debt financing
//Given Alberta’s
economic growth
profile, we’re very
excited about
new generation
opportunities in the
province.//
Craig Walter
Partner and GTA Energy Leader
KPMG LLP
The lack of offtake agreements
provides a challenge to debt financing
of projects. While some debt providers
have financed power projects in
Alberta without any offtake agreement,
these have typically been smaller hydro
plants. Providing debt financing to a
wind farm or a Combined Cycle Gas
Turbine (CCGT) plant will continue to
be challenging unless some market
mechanism can be introduced to
manage downside risk, or some level
of contracting can be arranged.
Gas Alberta: www.gasalberta.com
Solar resource is expressed in terms of solar irradiance per equivalent area in different jurisdictions
5
6
© 2014 KPMG LLP, a Canadian limited liability partnership and a member firm of the KPMG network of independent member firms affiliated with KPMG International Cooperative (“KPMG International”), a Swiss entity. All rights reserved.
Clean Energy Report | 03
Assessing the load growth challenge
There is a significant need for new
electricity generation capacity in
Alberta. By 2032, the AESO expects
peak demand to hit 18,194 MW, a
significant increase on the 10,599 MW
peak demand in 2012.7
This anticipated growth is a direct
result of Alberta’s growing oil sands
industry. Crude oil prices in the range
of $100/barrel, combined with low
interest rates, has led to predictions
that up to $218 billion could be
invested in Alberta’s oil sands sector
in the next 25 years. Alberta’s Energy
Resources Conservation Board
estimates that this investment could
lead to production almost doubling
to 3.8 million barrels per day in 2022,
up from 1.9 million barrels per day in
2012. 8
The oil sands industry is also indirectly
increasing electricity demand by
attracting an influx of workers and
their associated new non-commercial
demand. According to Alberta
Treasury Board and Finance, Alberta’s
population is projected to grow 2%
Source: Alberta Electric System Operator, AESO 2012
Long-term Outlook (Calgary, AB: AESO, 2012)
annually between 2012 and 2021,
before falling to 1.5% annual growth
between 2021 and 2041. 9
However, load growth is only part of the
story. New electricity generation is also
required to meet the planned closure
of a series of coal-fired power plants.
Federal government policy requires all
coal-fired generation to be retired at 45
years of operation or the expiration of
a plant’s power purchase agreement
(PPA). Proposed regulations due to be
enacted in 2015 also require coal-fired
generation capacity to curb carbon
emissions to natural gas levels. This will
make new coal plants relatively more
expensive from 2015.
These two factors will result in a series
of coal plant retirements during the next
two decades to the extent that only
5,906 MW of coal capacity is likely to
be operating by 2022 and 2,856 MW
by 2032, a considerable reduction from
the 6,242 MW that was operational
in 2012.10 Some major announced
retirements are shown in Figure 1:
Assumed coal generation retirements.
Power plant
//With planned
generation retirement
and strong demand
growth, Alberta is
poised to benefit
from renewable
energy investments
in the short and
medium term.//
Georges Arbache
Vice President
KPMG LLP
Retired
capacity by
2022
Power plant
Retired
capacity
(2022-2032)
1,344 MW
Sundance 5,6
807 MW
HR Milner
144 MW
Battle River 5
389 MW
Battle River 3,4
308 MW
Sheerness 1,2
780 MW
Keephills 1,2
780 MW
Sundance 1,2,3,4
Total
1,796 MW
Total
2,756 MW
Figure 1: Assumed coal generation retirements
Alberta Electric System Operator, AESO 2012 Long-term Outlook Update (Calgary, AB: AESO, 2013)
Alberta Energy Resources Conservation Board, Alberta’s Energy Reserves 2012 and Supply/Demand Outlook 2013–2022 (Calgary, AB: ERCB, 2013)
9
Alberta Treasury Board and Finance, Alberta Population Projection (Edmonton, AB: 2013)
7, 10
8
© 2014 KPMG LLP, a Canadian limited liability partnership and a member firm of the KPMG network of independent member firms affiliated with KPMG International Cooperative (“KPMG International”), a Swiss entity. All rights reserved.
04 | Clean Energy Report
Figure 2: Expected Alberta generation capacity
requirements
18
Load outlook
(winter peak)
16
Existing other
generation
Capacity (GW)
14
12
Existing effective
wind generation
10
8
Existing effective
hydro generation
6
Existing gas
generation
4
2
31
Existing coal
generation
20
29
20
27
20
25
20
23
20
21
20
19
20
17
20
15
20
13
20
20
11
0
Note: Effective capacity accounts for derates to intermittent renewable energy resources and is
therefore less than installed capacity.
//$13-$15 billion
will be invested
in transmission
assets in Alberta
in the next five to
10 years.//
Evan Bahry
Executive Director
Independent Power Producers Society of
Alberta
Source: Alberta Electric System Operator, AESO 2012 Long-term Outlook Update (Calgary, AB: AESO, 2013)
As shown in Figure 2: Expected Alberta
generation capacity requirements, peak
load will eclipse existing generation
capacity (including retirements) within
the next decade. The AESO estimates
that 6,190 MW of new effective
generation capacity will be brought
online in Alberta by 2022 to meet this
gap. By 2032, almost 13,000 MW of
new effective capacity will need to be
installed.11
Generation and load growth
driving transmission development
needs
Load growth is also forcing the
development of new transmission
capacity. No major new transmission
lines have been built in Alberta since
the 1980s, during which time the
population has grown by over one
11
12
million. In 2008, the last year for
which data is available, the cost of line
losses totalled $220 million, according
to Alberta Energy.12 In response, the
province has embarked on an extensive
transmission expansion program. The
most notable transmission projects are
outlined in Figure 3: Announced Alberta
transmission projects.
about $13 billion worth of generation in
recent years, which has resulted in the
grid becoming quite constrained. You
can’t easily build a new power plant
anywhere due to congestion. We need
another $20-$30 billion of generation
so we need to get the transmission in
place so that consumers can get power
and generators can connect to the grid.”
Evan Bahry, Executive Director at
the Independent Power Producers
Society of Alberta (IPPSA) summarizes
the need for new transmission
infrastructure. “Our bitumen is quite
remote, located up in Fort McMurray
which is quite a long way north of
Calgary,” he said. “All of the pipelines
across the province and the country
require electricity transmission. Some
$13-$15 billion will be invested in
transmission assets in Alberta in the
next five to 10 years. We have built
The province has decided to run a
competitive process in selecting
entities to construct and operate
transmission lines. The competitive
process introduces a new development
structure and has attracted the interest
of a number of non-incumbents.
The first project being tendered for
competition is the Fort McMurray West
500 kV Transmission Project, which
will transport electricity between the
Edmonton and Fort McMurray regions.
In January 2014 the AESO revealed
Alberta Electric System Operator, AESO 2012 Long-term Outlook Update (Calgary, AB: AESO, 2013)
Alberta Energy: www.energy.alberta.ca/Electricity/1773.asp
© 2014 KPMG LLP, a Canadian limited liability partnership and a member firm of the KPMG network of independent member firms affiliated with KPMG International Cooperative (“KPMG International”), a Swiss entity. All rights reserved.
Clean Energy Report | 05
Figure 3: Announced Alberta transmission projects
Bulk region
Cost
Expected/actual
commencement
date
Project
Description
Heartland 500 kV
(CTI)
Double circuit 500 kV line from Ellerslie to a new Northeast
500/240 kV substation near Fort Saskatchewan
$537 million
2013
West HVDC (CTI)
HVDC 500 kV line connecting the Wabamun
area near Genesee with the Calgary area at
Langdon
Edmonton
$1,329 million
2014
East HVDC (CTI)
HVDC 500 kV line connecting the Northeast
area at Heartland with the South area near
Brooks
Edmonton
$1,622 million
2014
Bickerdike - Little
Smoky
Double circuit 240 kV line from Bickerdike to
Little Smoky
Northwest
$205 million
2015
West Fort
McMurray
500 kV AC line connecting Wabamun area
near Genesee to the Northeast area near Fort
McMurray
Northwest
$1,649 million
2017
South area
transmission
reinforcement
Multiple 240 kV double circuit lines from and
within the south to the Calgary area
South
$2,287 million
2011-2017
Foothills area
transmission
development
240/138 kV Foothills substation near High River,
two double circuit 240 kV lines from Foothills to
east and west Calgary, and several local 240 kV
and 138 kV enhancements
South
$711 million
2014-2017
Source: Alberta Electric System Operator, AESO Long-term Transmission Plan (Calgary, AB: AESO, 2012)
the five consortia selected to enter the
request for qualification (RFQ) stage.
The winning bid will be announced in
December 2014.
Gas to meet capacity gap in the
short term
All major generators believe combined
cycle natural gas will meet most of the
growing demand requirement through
to 2020. As outlined in Figure 5:
13
Projected installed capacity in Alberta in
2022, the AESO estimates that natural
gas will account for 53% (11,036 MW)
of Alberta’s generation mix by 2022
(including cogeneration), up from 39%
(5,359 MW) in 2012. Wind deployment
is also expected to increase, but to
a lesser extent. The AESO predicts
that wind could account for 11%
(2,206 MW) of the energy mix by 2022,
almost doubling from 6% (865 MW) at
the beginning of 2012.13
“The most obvious new capacity is
large frame CCGT plants,” explained
Etienne Snyman, Manager, Business
Development at ATCO Power. “This
is certainly what ATCO is currently
pursuing. With Alberta being a
large gas supplier it is difficult to
justify anything else at this time. I
can’t really see coal being a major
contributor in the next 20 years due
to its cost and the environmental
implications.”
Alberta Electric System Operator, AESO 2012 Long-term Outlook Update (Calgary, AB: AESO, 2013)
© 2014 KPMG LLP, a Canadian limited liability partnership and a member firm of the KPMG network of independent member firms affiliated with KPMG International Cooperative (“KPMG International”), a Swiss entity. All rights reserved.
06 | Clean Energy Report
Figure 4: Installed capacity in Alberta in 2012
5,359MW
6,242MW
879MW
314MW
HYDRO
GAS
865MW
OTHER
WIND
COAL
Source: Alberta Electric System Operator, AESO 2012 Long-term Outlook Update (Calgary, AB: AESO, 2013)
Natural gas is expected to plug the
majority of the capacity gap as its
current low price is expected to
continue for at least the next five years,
reinforcing natural gas-fired supply as
the lowest cost new generation source
(see Figure 6 on page 7).
Given Alberta’s market based electricity
structure, the prevailing price of natural
gas directly sets hourly market prices
and, in turn, the economics of operating
existing plants and new generation
(refer to page 8, ‘Explaining Alberta’s
merchant power market’ for more
information on how the province’s
power market operates).
New gas fired generation is also
expected to be preferred in the next
five years as it is scaleable and not
geographically bound to the source
of the resource as with wind. This
flexibility will allow natural gas
facilities to locate at the sites of
retired coal plants to take advantage
Figure 5: Projected installed capacity in Alberta in 2022
621MW
11,036MW
5,906MW
894MW
HYDRO
OTHER
2,206MW
COAL
GAS
WIND
Source: Alberta Electric System Operator, AESO 2012 Long-term Outlook Update (Calgary, AB: AESO, 2013)
of existing infrastructure, transmission
connectivity, available water, a local
workforce and a pre-existing consent
of use for the site. These existing site
advantages are clearly a motivation for
TransAlta Utilities to build an 800 MW
CCGT power plant to replace part of its
Sundance coal complex on the south
shore of Wabamun Lake.
Other players have a line up of gas-fired
developments. “We have a site called
Saddle Brook Power that was permitted
in 2008,” explained Geoff Murray, Vice
President, Western Power Growth
at TransCanada. “Every player in the
market has one of these in the pipeline
to replace coal retirements. Capital
Power has talked about the Capital
Energy Centre. ATCO has up to 1,500
MW of combined cycle announced in
the Heartland area that they will build
in tranches and TransAlta has talked
about Sundance 7. This carries capacity
through to the turn of the decade.”
The large build-out of gas-fired plants
is already attracting the interest of
new market entrants in partnering
with incumbent Alberta-based owner/
operators. In October 2012, TransAlta
announced the formation of a new
strategic partnership with MidAmerican
Energy Holdings Company to develop
and own new natural gas-fuelled power
projects across Canada. The partnership
includes TransAlta’s planned 800 MW
gas-fired Sundance project, which will
be owned on a 50/50 basis.
Rob Schaefer, Corporate Development
at TransAlta, explains the motivations
for this partnership: “Access to capital
is not a significant hurdle, but what is
a bit more of a challenge is accepting
merchant risk and how much risk
you want to put into any one project.
Partnering is an option when companies
want to spread the risk, and this is what
we have done with MidAmerican.”
© 2014 KPMG LLP, a Canadian limited liability partnership and a member firm of the KPMG network of independent member firms affiliated with KPMG International Cooperative (“KPMG International”), a Swiss entity. All rights reserved.
Clean Energy Report | 07
Cogeneration will have
a role to play
While CCGT facilities will likely fill the
majority of the supply gap, behindthe-meter cogeneration projects will
also play a part in meeting power
demand in the oil sands industry.
Rob Schaefer explains some of
the opportunities and challenges
of cogeneration investments.
“Cogeneration is attractive as it
can provide generation behind-thefence so it avoids grid costs and
is also often more efficient than a
combined cycle plant. Cogeneration
has these advantages although it
tends to be more expensive to build.
One drawback to CCGT is that it
very rarely matches supply exactly.
Oil sands facilities have a lot higher
thermal than electric load, so getting
the balance is hard. You can either
build to meet the thermal load and
take a lot of excess power to the grid.
Or you can build the electric load and
put in boilers to meet the rest of the
thermal demand.”
Figure 6: Forecast monthly natural gas prices
(Intra-Alberta C$/GJ) 4.0
3.5
3.0
C$/GJ
2.5
2.0
1.5
1.0
0.5
0.0
JAN
FEB
MAR
APR
MAY
JUN
JUL
AUG
SEP
OCT
NOV
DEC
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FEB
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Brian Vaasjo, CEO of Capital Power,
also shared his thoughts on the new
players entering the Alberta market:
“Coal plant retirements will result
in very significant requirements for
additional generation. This will largely
be met through large combined cycle
natural gas plants. This may provide
an opportunity for new entrants into
the market. There is a lot of talk
about new entrants to the market and
we are hearing of a lot of enquiries
from generators such as the large
North American independent power
producers who want to enter the
Alberta market.”
2011
2012
2013
2014
Source: Gas Alberta Inc (Calgary, AB: 2013)
//Cogeneration is attractive
as it can provide generation
behind-the-fence so it
avoids grid costs and is
also often more efficient
than a combined cycle
plant.//
Rob Schaefer
Corporate Development
TransAlta
© 2014 KPMG LLP, a Canadian limited liability partnership and a member firm of the KPMG network of independent member firms affiliated with KPMG International
Cooperative (“KPMG International”), a Swiss entity. All rights reserved.
2015
08 | Clean Energy Report
Explaining Alberta’s
merchant power market
Unlike most other Canadian provinces, Alberta operates a deregulated electricity
system whereby all electricity that is not self-supplied must be exchanged through
the Alberta power pool. In contrast to most other provinces that provide long-term
contracts for independent power producers, Alberta does not have organized
programs for long-term contracting. The power pool functions as a spot market,
matching demand and supply to establish an hourly pool price. Generators must
submit their offer to supply electricity in MWh blocks for each hourly period during
the next seven days.
The System Controller forms a supply schedule based on a ranking of the bids from
the least to the most expensive. The electricity price is determined by taking the
weighted average of the system price over an hourly basis. All power producers
receive the hourly pool price for power generated. In contrast, the electricity transmission and distribution market is regulated and financed by ratepayers.
This deregulated market structure appears to be working in terms of encouraging
investment in new generation while maintaining stable prices. As shown in Figure 7,
between 2003 and 2012 Alberta’s net market generation capacity increased 25%
while prices remained stable. The average hourly pool price was $64.32 per MWh in
2012, a 16% decrease on 2011 and a 2% increase on a decade ago.14
150
15,000
120
12,000
90
9,000
60
6,000
30
3,000
12
20
11
20
10
20
09
20
08
20
07
20
06
20
05
20
04
0
20
20
03
0
Installed capacity (MW)
Average pool price (C$ per MWh)
Figure 7: Average annual Alberta electricity pool
prices and installed capacity
Off-peak average pool price
On-peak average pool price
Average hourly pool price
Installed capacity
Source: Alberta Electric System Operator, AESO Long-term Transmission Plan (Calgary, AB: AESO, 2012)
14
Alberta Electric System Operator, AESO Long-term Transmission Plan (Calgary, AB: AESO, 2012)
© 2014 KPMG LLP, a Canadian limited liability partnership and a member firm of the KPMG network of independent member firms affiliated with KPMG International Cooperative (“KPMG International”),
a Swiss entity. All rights reserved.
Clean Energy Report | 09
Wind – a viable long-term
complement to gas?
Current gas prices limit the
business case for new wind
generation
While Alberta has some of Canada’s
best wind resources and as such can
deliver strong technical project fundamentals, the majority of stakeholders
interviewed for this report believe that
the current low gas price environment
limits the economic viability of new
wind projects. Natural gas prices in
Alberta are not forecast to increase substantially in the foreseeable future.
//The reality of
the situation is
that jurisdictions
have system
capacity restrictions
associated with
renewable energy
that is intermittent.//
Brian Vaasjo
President & CEO
Capital Power Corporation
As Mary Hemmingsen, Partner and
National Power and Utilities Sector Lead
at KPMG LLP, explains, wind projects
are further challenged as they receive
a discount to the average market price.
“Wind production, being intermittent
and not dispatchable, floods the market
with supply and depresses the price
at the time wind is able to generate.
So realized prices for wind production
are considerably less than the average
market price. This circumstance is
exacerbated by the concentration
of wind farms in the southwest (of
Alberta) where there is a superior
wind resource that generally results in
a significant volume of wind capacity
coming online simultaneously.”
Rob Roberti, Senior Vice President
of Power Generation at Capstone
Infrastructure Corp, believes that this
discount is increasing. “In 2013, the
wind discount to the average power
pool price was 46%,” he said. “Wind
does not always generate when power
prices are high. In a 10,000-12,000 MW
capacity market, 700-1,000 MW of
wind coming online at the same time
causes the price to decrease. Most
of Alberta’s wind farms are located in
south-western Alberta so wind capacity
can go from 200 MW to 800 MW
rather quickly. Just a few years ago this
discount was in the 20%-30% range.
The discount is now pushing 50%
and as more wind comes online this
discount will get worse. This is difficult
for the wind generators, although it
does show how more wind can push
down energy costs.”
Another major obstacle for wind energy
in Alberta is the lack of transmission
capacity in the grid. With some
1,117 MW of wind concentrated around
a limited number of locations, the
capacity of the system to carry more
wind is currently limited. However, as
mentioned earlier, Alberta is currently
undertaking a significant transmission
expansion program, which should
alleviate some of these constraints.
“The reality of the situation is that
jurisdictions have system capacity
restrictions associated with renewable
energy that is intermittent,” explained
Brian Vaasjo. “You can only have so
much wind in the system and Alberta
already has a lot. We are getting pretty
close to the technical limits of that. This
doesn’t mean that more can’t be built,
but the cost from a system perspective
goes up pretty dramatically.”
However, gas prices may rise over time
to allow wind to become competitive
by the end of the decade. “There will
be smaller renewable energy projects
© 2014 KPMG LLP, a Canadian limited liability partnership and a member firm of the KPMG network of independent member firms affiliated with KPMG International Cooperative (“KPMG International”), a Swiss entity. All rights reserved.
10 | Clean Energy Report
//With continued
technology
innovation to reduce
renewable supply
costs, supportive
carbon policies and
demand pushing
market prices,
wind and other
renewables can have
a prominent role
in Alberta’s future
supply mix.//
Mary Hemmingsen
Partner and National Power & Utilities
Sector Leader
KPMG LLP
around biomass and other technologies,”
explained Brian Vaasjo. “But in terms of
larger scale projects, I don’t really see
it happening until power prices go up.
In the next few years power prices are
expected to remain relatively low. When
prices go up, grid parity with renewables
will become reality if technology can
continue to become more efficient and
capital costs go down.”
Extra market support for wind
projects no longer available
Despite the current unfavourable
economics of wind energy, two
large projects moved forward in
the past 12 months. In December
2012, the 150 MW Halkirk wind
farm sponsored by Capital Power
commenced commercial operations.
Six months later construction of the
300 MW Blackspring Ridge wind farm
commenced following its acquisition
by EDF EN Canada and Enbridge. This
project will surpass Halkirk as Alberta’s
largest wind farm when it comes online
in the summer of 2014.
Both projects managed to secure
20-year agreements for RECs from
Californian utility Pacific Gas and
Electric Company, which made the
projects economically viable. The
REC purchase provides the projects
with an additional income stream to
the revenues received from selling
into the Alberta power pool at the
spot market price. However, as Rob
Roberti explains, the sale of RECs to
California is no longer an option for
Alberta generators. “The bulk of the
investment in wind has been two big
projects that benefitted from unique
financing circumstances in that they
sold RECs to the California market,”
he said. “We do not expect this to
happen again, making these projects
a one-off. California has changed
its regulations to cap the number of
RECs that can go to regions outside
California.”
Carbon offsets drive wind
investment
Wind energy projects in Alberta have
been driven by the need to offset
carbon emissions. In 2007, the Alberta
government introduced the Specified
Gas Emitters Regulation, which sets
gas intensity limits for large emitters
of greenhouse gases in the province.
The regulation states that large emitters must reduce emissions intensity
by 12% from an average baseline year
after nine years of operation.
Should an emitter not meet these
targets, it must comply by either paying
$15 per tonne into the Climate Change
and Emissions Management Fund for
every tonne that exceeds the reduction
target, or by purchasing emission
offsets generated from Alberta-based
projects that are not subject to the
regulation, including wind farms. A
third option is to purchase Emissions
Performance Credits from a different
Alberta facility that has exceeded its
emissions reduction target.
This regulation led to a number of large
oil and gas companies with significant
emissions investing in wind farms
in order to obtain offsets for their
emissions. For example, Canadian oil
and gas company Nexen, which is now
owned by Chinese energy company
CNOOC, invested in the 70.5 MW
Soderglen wind farm that came online
in 2006. Nexen owns 50% of the
project but 100% of the carbon credits,
which can be used to help meet its
emissions reduction target. Energy
companies Suncor and Enbridge have
also built wind farms in Alberta in order
to offset carbon emissions.
© 2014 KPMG LLP, a Canadian limited liability partnership and a member firm of the KPMG network of independent member firms affiliated with KPMG
International Cooperative (“KPMG International”), a Swiss entity. All rights reserved.
Clean Energy Report | 11
New policy could redefine investment
landscape
New emissions policy could
revitalize wind
An increase in carbon emissions
targets and the carbon price is likely to
bode well for renewables generation
and drive large emitters to invest in
wind energy projects for their offset
potential. The Alberta government is
currently considering bolstering its
emissions regulation to build social
license for its carbon-intensive oil sands
industry and multi-billion dollar pipeline
projects such as Keystone XL, which
will transport bitumen to the US. There
has been considerable speculation that
the Alberta government will introduce
more aggressive benchmarks such as
a “40/40 target”, which will increase
the carbon emissions target for large
emitters from 12% to 40% and increase
the carbon price from $15 per tonne
to $40 per tonne. However, it should
be noted that the Alberta government
has not clarified how it will change the
current regulation.
An increase in carbon emissions
targets and the carbon price is likely to
bode well for renewables generation
and drive large emitters to invest in
wind energy projects for their offset
potential.
“Alberta has a significant emissions
challenge with the oil sands
development,” explained Evan Bahry.
“Next year Alberta is looking at redoing
its Specified Gas Emitters Regulation.
We were one of the first North
American jurisdictions to put a price on
carbon at $15 per tonne. The province
recognizes that it needs to reduce its
15
emissions so it will likely increase its
emissions cost to those who emit. This
creates an offset potential for wind. The
province has signalled that they need
to do more but they haven’t offered any
clarity yet. This will be important.”
Wind is also likely to become more
attractive from an offset perspective
regardless of policy revisions. Some
large emitters have already adopted
corporate policies that encourage
carbon offsetting. For example,
Enbridge has adopted a ‘Neutral
Footprint’ commitment to generate a
kilowatt of renewable energy for every
kilowatt of conventional electricity that
the company’s operations consume.
Oil and gas companies are most likely
to be compelled to invest in wind
projects for their offset potential. As
depicted in Figure 8, the oil sands
industry accounted for 23% of Alberta’s
greenhouse gas emissions in 2011
while the oil, gas and mining sector
accounted for 18%, according to Alberta
Ministry of Environment and Sustainable
Resource Development.15 Electricity
and heat generation companies account
for 20% of greenhouse emissions but
are unlikely to invest in wind farms
specifically for their offset potential.
This is because many power utilities
are already reducing carbon emissions
by replacing aged coal-fired plants with
cleaner CCGT plants.
“When you look at the carbon footprint
of Alberta, coal plant retirement that is
required by law will lead to a dramatic
reduction in carbon emissions,”
confirmed Brian Vaasjo. “So from the
power generation side you are replacing
coal with natural gas. Replacing natural
gas with wind is not that much of a step
in reducing carbon emissions.”
Figure 8: Alberta greenhouse gas emissions by sector
National Inventory Report 2011
5%
6%
7%
4%
23%
1%
16%
20%
18%
Oil sands
Residential/commercial
Electricity & heat
generation
Manufacturing/
construction
Oil, gas and mining
Industrial process
Transportation
Waste
Agriculture
Source: Alberta Ministry of Environment and Sustainable Resource Development, National Inventory Report
(Edmonton, AB, 2011)
Alberta Ministry of Environment and Sustainable Resource Development, National Inventory Report (Edmonton, AB, 2011)
© 2014 KPMG LLP, a Canadian limited liability partnership and a member firm of the KPMG network of independent member firms affiliated with KPMG International Cooperative (“KPMG International”), a Swiss entity. All rights reserved.
12 | Clean Energy Report
New renewable energy framework
could catalyze solar and wind
Investment in solar and wind could be catalyzed by a new
renewable energy framework the province is currently
considering. Alberta Energy, the province’s energy
ministry, is currently drafting a policy framework for
implementation in 2014. No details on the structure
have been revealed, but the government is expected
to favour a clean energy standard, which will limit
greenhouse gas emissions in the electricity sector.
Any new policy framework is expected to be in line
with Alberta’s current merchant market structure.
Other options include requiring generators to
produce a certain percentage of electricity from
renewable sources, or the introduction of an
Ontario-style feed-in tariff.
“Alberta’s push to green its electricity grid is
not being driven by the renewable industry
alone,” explained John Gorman, President
of CanSIA. “The Premier and her cabinet
ministers are actively talking about the need
for Alberta to establish the social licence
nationally and internationally so that it may
drive ahead with projects like Keystone
XL and continue to develop its oil and
gas resources. This is a significant
factor in what is driving them to
come forward with the Alternative
Renewable Energy Framework.
There is a perfect storm in Alberta
right now and renewables may
end up a safe harbour for the long
term.”
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liability partnership and a member firm
of the KPMG network of independent
member firms affiliated with KPMG
International Cooperative (“KPMG
International”), a Swiss entity. All
rights reserved.
Clean Energy Report | 13
Tapping Alberta’s solar
resource
//Solar is
nearing grid or
socket parity
now, so will likely
be extremely
competitive in
as little as five
or six years as
conventional
electricity prices
are expected to
rise in Alberta.//
Ron Seftel
Senior Vice President
Bullfrog Power
Solar is often left out of the debate
when it comes to Alberta’s energy mix
despite the province having the best
solar resource in Canada. According
to CanSIA, Alberta’s solar resource is
25% better than Ontario’s and 30%
better than Germany’s, both of which
have seen significant solar installation
driven by subsidies. In the absence
of mechanisms to stimulate solar
development, Alberta has virtually no
installed solar capacity at present.
As is the case with wind energy, solar
PV could be more heavily deployed
in the next five years if, as is widely
anticipated, the government introduces
policy that puts more pressure on
industry to reduce carbon emissions
and, in turn, incentivizes investment
in renewables. Solar may also prove
compelling due to its improving cost
profile and superior output profile.
“Solar could make sense for moments
when wind output is generally
low on hot summer days when air
conditioning is ramping up,” explained
Rob Roberti. “Given the decrease
in solar costs, solar is close to being
at grid parity at these times of day.
Southeast Alberta has some of the
best solar resource in Canada. If
you just look at the average price
then solar is not at grid parity in
Alberta. That said, when you take into
consideration that the average peak
price is close to grid parity and that
you are going to make the bulk of your
margin when the power price spikes
to over $80 per MWh, solar might
make sense.”
One of the main challenges for
utility-scale solar projects in Alberta
is that the market price differentials
for solar are not close relative to
conventional resources. “On the utility
scale front, the market mechanism
does not provide for power purchase
agreements,” explains John Gorman.
“The government will have to come up
with a policy or program that addresses
this as we move forward with replacing
coal assets. We are discussing a
strategy with the provincial government
for both utility-scale and distributed
solar generation and there is certainly
potential for both. We haven’t looked at
how much solar PV could be installed in
Alberta but our recommendation to the
Ontario government is that solar could
account for 5% of electricity demand at
any one time.”
As Ron Seftel, Senior Vice President,
Operations at Bullfrog Power explains,
the initial adopters of solar PV will be
municipal organizations. “As with all
renewable energy installations, these
are long term projects. From a financial
perspective, if you are in a position to
consider the long term return, maybe
over 15 or 20 years, then solar is very
attractive. Solar is nearing grid or socket
parity now, so will likely be extremely
competitive in as little as five or six years
as conventional electricity prices are
expected to rise in Alberta. Not everyone
can take this long-term view but certainly
municipalities and school boards who
know they are going to be around for 20
years can, so they will likely be the initial
adopters of solar and will help to kickstart the local industry.”
© 2014 KPMG LLP, a Canadian limited liability partnership and a member firm of the KPMG network of independent member firms affiliated with KPMG International Cooperative (“KPMG International”), a Swiss entity. All rights reserved.
14 | Clean Energy Report
Bringing financing into Alberta’s
merchant market – an issue of growing
importance
Incumbent generators in Alberta are
sufficiently capitalized to fund their
pipeline of CCGT projects earmarked to
replace retired coal capacity from 2017.
Major generators such as TransCanada
and ATCO both have large balance
sheets. TransAlta has established
a partnership with MidAmerican to
share financing its pipeline of gasfired generation projects, while Capital
Power has already structured financing
for its planned Shepard Energy Centre.
However there is a growing interest in
alternative financing mechanisms for
new market entrants to finance power
assets.
These new participants will be keen
to explore alternatives to balance
sheet financing, including project debt
financing and equity co-investment.
Alberta’s merchant market structure
and limited liquidity due to the
islanded nature of the power market,
exacerbated by self supply, means that
project financing will prove challenging.
“The lack of offtake agreements
makes it very difficult to bring debt
finance into contracts,” confirms
Etienne Snyman. “With PPAs, lenders
have some cash flow stability and a
basis upon which they can lend to.
There are some creative mechanisms
that can be used to secure debt
financing, particularly when it comes to
cogeneration. One of the mechanisms
would be to sell some of the power
from cogeneration behind the fence
and as such get a long-term contract,
enabling project financing. It will
continue to be very hard for large
stand-alone CCGT projects to secure
project financing unless you can get
a contract over the transmission
system.”
As John Vincent, Senior Managing
Director, Head of Project Finance at
Sun Life Financial explains, some
debt providers have financed power
projects in Alberta without an offtake
contract, although these have typically
been hydro projects. “We have done
merchant financing but the leverage
has always been much lower than
what you would get with a contractual
cashflow. We have only done this
for hydro projects that have very low
operating costs so are always going
to be running. This desensitizes them
to low power prices at certain times
of the day. There are some nuances
with hydro that are quite interesting in
that it can be peaked depending on the
situation to ensure you are producing
when power prices are the highest.”
“But providing debt financing into a
wind farm or a CCGT plant will be
pretty hard in Alberta unless someone
is willing to protect against a downside
case, which could be in the form of
a PPA or another vehicle,” continued
Vincent. “Some organizations such as
local utilities and cities are looking at
stepping in and making arrangements
to backstop a power purchase
arrangements of sorts. We are certainly
open to solutions like this.”
One way to attract debt project
financing is to introduce a degree of
contracting into the market structure.
This would provide debt providers
with the long term revenue certainty
needed to invest. How this could be
incorporated into Alberta’s merchant
market structure is an outstanding
issue. Nevertheless, this is something
that some of Alberta’s leading
generators believe should be given
some consideration given the sizeable
need for new capacity.
“It is important that government
think carefully about whether we
need structural change post 2020,”
explained Geoff Murray. “Deregulation
was a long time in the making. If
we are going to reverse this or even
nibble around the edges we need
time to really think about this. I don’t
think there needs to be a wholesale
philosophical change but I do think
actions will need to be taken to move
things along towards some sort of
mid to long-term contracting. This
could take the form of incentivizing or
requiring contracting for some players.
This would enable low-cost capital on
the debt and equity side to be brought
into the market. Contracts also enable
companies to invest the huge sums
over long periods of time that are
required to develop large baseload
capacity.”
© 2014 KPMG LLP, a Canadian limited liability partnership and a member firm of the KPMG network of independent member firms affiliated with KPMG International Cooperative (“KPMG International”), a Swiss entity. All rights reserved.
Clean Energy Report | 15
Leadership in the Power
& Utilities Industry
KPMG has built one of Canada’s largest Power & Utilities practices
comprised of professionals who have relevant industry backgrounds
and devote their talent and tactical skills to helping clients grow,
enhance shareholder value and succeed in the marketplace.
KPMG’s Power and Utilities team serve organizations involved
in all aspects of the Power & Utilities sector, from generation
and transmission through to distribution and retail. Our
multi-disciplined professionals understand the sector’s unique
and ever-changing issues that affect the entire industry,
as well as regional regulatory complexities. We offer
customized, industry-focused Audit, Tax, and Advisory
services. Our industry-trained and highly qualified
professionals focus on company specific needs and draw
on international resources when required.
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Clean Energy Report | 17
Appendix
Notable renewable energy asset/project debt finance deals in Canada (2013)
Note: This table only includes deals over C$100 million for which the volume of debt financing is disclosed
March 2013
South Kent Wind Farm (270 MW)
Ontario
Owners
Pattern Energy Group LP / Samsung
Renewable Energy Inc.
Debt
providers
Nord LB / Union Bank / Natixis / Societe Generale / Manulife
Financial Corp. / Bank of Tokyo-Mitsubishi UFJ / Mizuho
Corporate Bank Ltd. / Royal Bank of Scotland Group plc /
KeyBank / Bayern LB / CIBC World Markets Inc. / Credit
Agricole Corporate and Investment Bank / Siemens Bank
GmbH / BMO Financial Group / Royal Bank of Canada
Financing volume
C$700 million
Financing type
Construction & term loan
Tenor (years)
Construction + 7 years
Rate (%)
N/D
October 2013
Grand Renewable Solar Energy Park (100 MW)
Ontario
Owners
Connor, Clark & Lunn Infrastructure Ltd. /
Samsung Renewable Energy Inc..
Debt
providers
Nord LB / Natixis / Rabobank / Bank of Tokyo-Mitsubishi UFJ
/ KeyBank / Canadian Imperial Bank of Commerce / National
Bank of Canada / Caisse centrale Desjardins / Royal Bank of
Canada
Financing volume
C$525 million
Financing type
Construction & term loan
Tenor (years)
N/D
Rate (%)
N/D
February 2013
Comber Wind Farm (166 MW)
Ontario
Owners
Brookfield Renewable Energy Partners LP
Debt
providers
Scotia Capital Inc.
Financing volume
C$450 million
Financing type
Bond refinancing
Tenor (years)
17.75 years
Rate (%)
5.13%
Borealis Solar Portfolio (108 MW)
Ontario
December 2013
Advised by KPMG
Owners
Metropolitan Life Insurance Company /
Fiera Axium Infrastructure Inc.
Debt
providers
Sun Life Assurance Company of Canada / National Bank
Financial Inc.
Financing volume
C$390 million
Financing type
Construction and term loan
Tenor (years)
Construction + 19 years
Rate (%)
N/D
June 2013
Vents du Kempt Wind Farm (101 MW)
Québec
Owners
Eolectric Inc. / Fiera Axium
Infrastructure Inc.
Debt
providers
Manulife Financial Corp. / Caisse de dépôt et placement du
Québec / KfW IPEX Bank
Financing volume
C$300 million
Financing type
Construction and term loan
Tenor (years)
N/D
Rate (%)
N/D
© 2014 KPMG LLP, a Canadian limited liability partnership and a member firm of the KPMG network of independent member firms affiliated with KPMG International Cooperative (“KPMG International”), a Swiss entity. All rights reserved.
18 | Clean Energy Report
August 2013
Walpole, Belmont & Amherstburg Solar Plants (20 MW)
Ontario
Owners
Alterra Power Corp. / GE Energy
Financial Services
Debt
providers
Manulife Financial Corp. / Sun Life Assurance Company
of Canada / Canada Life Assurance Company / Caisse de
dépôt et placement du Québec / Great-West Life Assurance
Company
Financing volume
C$200 million
Financing type
Acquisition finance
Tenor (years)
N/D
Rate (%)
N/D
November 2013
Fort St. James Biomass Plant (33 MW)
British Columbia
Owners
Dalkia plc / Fengate Capital
Management
Debt
providers
Natixis / Rabobank / Bank of Tokyo-Mitsubishi UFJ / Canadian
Imperial Bank of Commerce / National Bank of Canada
Financing volume
C$175 million
Financing type
Construction and term loan
Tenor (years)
N/D
Rate (%)
N/D
June 2013
FieStar Solar Portfolio (42 MW)
Ontario
Owners
Starwood Energy Group Global LLC /
Fiera Axium Infrastructure Inc.
Debt
providers
Nord LB / Natixis / Bank of Tokyo-Mitsubishi UFJ
Financing volume
C$175 million
Financing type
Construction and term loan
Tenor (years)
N/D
Rate (%)
N/D
October 2013
Seigneurie de Beaupre phase II Wind Farm (68 MW)
Québec
Owners
Gaz Metro LP / Valener Inc.
Debt
providers
Sun Life Assurance Company of Canada / Industrial Alliance
Insurance and Financial Services Inc. / KfW IPEX Bank
Financing volume
C$166 million
Financing type
Construction term loan, bridge financing, letter of credit facility
Tenor (years)
Construction + 19.5 years
Rate (%)
N/D
March 2013
Essex County Solar Plant (51 MW)
Ontario
Owners
Brookfield Renewable Energy Partners
LP
Debt
providers
Bank of Tokyo-Mitsubishi UFJ / Siemens Financial Services
Ltd. / Laurentian Bank of Canada
Financing volume
C$150 million
Financing type
Refinancing
Tenor (years)
N/D
Rate (%)
N/D
March 2013
Gosfield Wind Farm (50.6 MW)
Ontario
Owners
Brookfield Renewable Energy Partners
LP
Debt
providers
Bank of Tokyo-Mitsubishi UFJ / Siemens Financial Services
Ltd. / Laurentian Bank of Canada
Financing volume
C$130 million
Financing type
Construction and term loan
Tenor (years)
N/D
Rate (%)
N/D
Continued >
© 2014 KPMG LLP, a Canadian limited liability partnership and a member firm of the KPMG network of independent member firms affiliated with KPMG International Cooperative (“KPMG International”), a Swiss entity. All rights reserved.
Clean Energy Report | 19
August 2013
White River - Gitchi Animki Hydro Plant (19 MW)
Ontario
Owners
Regional Power / Pic Mobert First
Nation
Debt
providers
Manulife Financial Corp.
Financing volume
C$126 million
Financing type
Construction and term loan
Tenor (years)
N/D
Rate (%)
N/D
July 2013
Glen Dhu Wind Farm (62.1 MW)
Nova Scotia
Owners
Glen Dhu Wind Energy LP
Debt
providers
Stonebridge Financial Corp.
Financing volume
C$115 million
Financing type
Refinancing
Tenor (years)
17.5 years
Rate (%)
5.33%
October 2013
CSI Solar Project 3 (30 MW)
Ontario
Owners
Canadian Solar Inc.
Debt
providers
Deutsche Bank AG
Financing volume
C$105 million
Financing type
Construction loan
Tenor (years)
1.75 years
Rate (%)
N/D
October 2013
Solar Portfolio (30 MW)
Ontario
Owners
Canadian Solar Inc.
Debt
providers
Deutsche Bank AG
Financing volume
C$104 million
Financing type
Construction loan
Tenor (years)
1 year
Rate (%)
N/D
November 2013
Mackenzie Biomass Plant (36 MW)
British Columbia
Owners
Conifex Timber Inc.
Debt
providers
Canadian Imperial Bank of Commerce / Integrated Private
Debt Corp. / Business Development Bank of Canada / Export
Development Canada (EDC)
Financing volume
C$103 million
Financing type
Construction and term loan
Tenor (years)
6 years
Rate (%)
N/D
Source: Clean Energy Pipeline asset/project finance deal database
© 2014 KPMG LLP, a Canadian limited liability partnership and a member firm of the KPMG network of independent member firms affiliated with KPMG International Cooperative (“KPMG International”), a Swiss entity. All rights reserved.
20 | Clean Energy Report
Asia
North America
Europe
4-Quarter moving average
13
13
Rest of the world
4Q
13
3Q
13
2Q
12
1Q
12
4Q
3Q
2Q
1Q
4Q
3Q
2Q
1Q
4Q
3Q
2Q
1Q
4Q
3Q
2Q
1Q
12
0
12
0
11
10
11
10
11
20
11
20
10
30
10
30
10
40
10
40
09
50
09
50
09
60
09
60
Number of deals
Deal value ($ billion)
Global renewable energy project finance by region
Source: Clean Energy Pipeline asset/project finance deal database
Europe: project finance
volume by sector as a % of
total debt raised - 2013
North America: project
finance volume by sector
as a % of total debt raised 2013
46%
57%
46%
WIND
23%
SOLAR
WIND
China: project finance
volume by sector as a % of
total debt raised - 2013
56%
SOLAR
31%
WIND
SOLAR
12%
BIOENERGY
8%
10%
4%
BIOENERGY
OTHER
3%
HYDRO
BIOENERGY
OTHER
1%
3%
OTHER
Source: Clean Energy Pipeline asset/project finance deal database
© 2014 KPMG LLP, a Canadian limited liability partnership and a member firm of the KPMG network of independent member firms affiliated with KPMG International Cooperative (“KPMG International”), a Swiss entity. All rights reserved.
© 2014 KPMG LLP, a Canadian limited liability partnership and a member firm of the KPMG network of independent member firms affiliated with KPMG International Cooperative (“KPMG International”), a Swiss entity. All rights reserved.
About the research
This report provides insight into financing, investment and development trends in Canada’s clean energy
sector. The research for this report was provided by Clean Energy Pipeline, a specialist provider of
research, data and news on the clean energy sector.
Both articles in this report include comments from interviews conducted with the following individuals:
•
•
•
•
•
•
•
•
•
Etienne Snyman, Manager, Business Development, ATCO Power Ltd
Ron Seftel, Senior Vice President, Operations, Bullfrog Power
John Gorman, President, Canadian Solar Industries Association
Brian Vaasjo, President & CEO, Capital Power Corporation
Rob Roberti, Senior Vice President of Power Generation, Capstone Infrastructure Corporation
Evan Bahry, Executive Director, Independent Power Producers Society of Alberta
John Vincent, Senior Managing Director, Head of Project Finance, Sun Life Financial
Rob Schaefer, Executive Vice President, Trading and Marketing, TransAlta Corporation
Geoff Murray, Vice President, Western Power Growth, TransCanada Corporation
Mary Hemmingsen
Partner
Advisory Services, National Sector Leader
Power and Utilities
T: 416 777 8896
E: mhemmingsen@kpmg.ca
Trevor Hammond
Partner
Audit
T: 403 691 7913
E: trevorhammond@kpmg.ca
Craig Walter
Partner
GTA Energy Leader
Infrastructure Advisory and Transaction Services
T: 416 777 8342
E: cwalter1@kpmg.ca
Stephen Spooner
Partner
Advisory
T: 403 691 8403
E: stephenspooner@kpmg.ca
Georges Arbache
Vice President
Infrastructure Advisory Development
M&A and Strategy
T: 416 777 8170
E: garbache@kpmg.ca
kpmg.com/ca/powerutilities
The information contained herein is of a general nature and is not intended to address the circumstances of any particular individual or entity. Although we
endeavor to provide accurate and timely information, there can be no guarantee that such information is accurate as of the date it is received or that it will continue
to be accurate in the future. No one should act on such information without appropriate professional advice after a thorough examination of the particular situation.
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