Study No. 155
January 2016
CANADIAN
ENERGY
RESEARCH
INSTITUTE
AN ASSESSMENT OF HYDROELECTRIC
POWER OPTIONS TO SATISFY OIL SANDS
ELECTRICITY DEMAND
Canadian Energy Research Institute | Relevant • Independent • Objective
AN ASSESSMENT OF HYDROELECTRIC POWER OPTIONS TO
SATISFY OIL SANDS ELECTRICITY DEMAND
An Assessment of Hydroelectric Power Options to Satisfy
Oil Sands Electricity Demand
Author:
Ganesh Doluweera
ISBN 1-927037-39-3
Copyright © Canadian Energy Research Institute, 2016
Sections of this study may be reproduced in magazines and newspapers with acknowledgement
to the Canadian Energy Research Institute
January 2016
Printed in Canada
Front Photo Courtesy of istockphoto.com
Acknowledgements:
The author of this report would like to extend his thanks and sincere gratitude to all CERI staff
that provided insightful comments and essential data inputs required for the completion of this
report, as well as those involved in the production, reviewing, and editing of the material,
including but not limited to Allan Fogwill, Dinara Millington and Megan Murphy. The author
would also like to personally thank Dr. David Layzell of the University of Calgary for providing
helpful insights for this study.
ABOUT THE CANADIAN ENERGY RESEARCH INSTITUTE
The Canadian Energy Research Institute is an independent, not-for-profit research establishment created
through a partnership of industry, academia, and government in 1975. Our mission is to provide relevant,
independent, objective economic research in energy and environmental issues to benefit business,
government, academia and the public. We strive to build bridges between scholarship and
policy, combining the insights of scientific research, economic analysis, and practical experience.
For more information about CERI, visit www.ceri.ca
CANADIAN ENERGY RESEARCH INSTITUTE
150, 3512 – 33 Street NW
Calgary, Alberta T2L 2A6
Email: [email protected]
Phone: 403-282-1231
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An Assessment of Hydroelectric Power Options to Satisfy
Oil Sands Electricity Demand
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Table of Contents
LIST OF FIGURES ..............................................................................................................
LIST OF TABLES ................................................................................................................
EXECUTIVE SUMMARY .....................................................................................................
CHAPTER 1 INTRODUCTION .........................................................................................
Oil Sands Electricity Demand and the Opportunity to Reduce GHG Emissions .................
Hydroelectric Power Generation Options ..........................................................................
Transmission Options to Move Hydropower ......................................................................
Scope and Objectives ..........................................................................................................
CHAPTER 2 METHODOLOGY ........................................................................................
Hydropower Generation Options .......................................................................................
Hydropower Generation Options in Alberta ..................................................................
Hydropower Generation Options in British Columbia ...................................................
Hydropower Generation Options in Manitoba ..............................................................
Transmission Options..........................................................................................................
Selection of Transmission Line Corridors .......................................................................
Levelized Cost of Delivered Electricity and GHG Emissions Abatement Cost ....................
Uncertainty Assessment .....................................................................................................
Estimation of Environmental and Social Impacts ...............................................................
Residential and Property Value Impacts ........................................................................
Agricultural Impacts .......................................................................................................
Impacts on Indigenous Populations ...............................................................................
Environmental Impacts ..................................................................................................
CHAPTER 3 RESULTS ....................................................................................................
Hydropower Generation and Transmission Options ..........................................................
Alberta-BC Options .........................................................................................................
Alberta-Manitoba Option ...............................................................................................
Alberta Slave River Options ............................................................................................
Levelized Cost of Electricity and Cost of Avoided CO2 ........................................................
Sensitivity Analysis against Discount Rate ..........................................................................
Economic Assessment of Electrical Extraction Technologies .............................................
Social and Environmental Impacts of Hydropower Options ..............................................
Employment and Other Economic Development Benefits.................................................
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CHAPTER 4 DISCUSSION AND CONCLUDING REMARKS ................................................
Implications of the Alberta Electricity Market Structure on Hydropower
Project Financing ............................................................................................................
Alberta-British Columbia Hydropower Options ..................................................................
Alberta Slave River Hydropower Options ...........................................................................
Alberta-Manitoba Hydropower Options.............................................................................
Electrical Extraction Technologies as a Carbon Management Option ...............................
Long-term Planning .............................................................................................................
APPENDIX A SOCIAL AND ENVIRONMENTAL IMPACTS WITHIN THE STUDY AREA ...........
APPENDIX B CALCULATION OF ENERGY COST AND EMISSIONS OF BITUMEN
EXTRACTION THROUGH SAGD................................................................................
APPENDIX C UNCERTAINTY ANALYSIS OF LCOE AND CACO2 ...........................................
BIBLIOGRAPHY ................................................................................................................
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List of Figures
E.1
E.2
E.3
1.1
1.2
1.3
1.4
1.5
1.6
1.7
2.1
3.1
3.2
3.3
3.4
3.5
3.6
3.7
3.8
3.9
3.10
3.11
3.12
3.13
3.14
3.15
3.16
A.1
A.2
A.3
A.4
B.1
Average Cost of Delivered Electricity of Different Generation and
Transmission Options....................................................................................................
Cost of Avoided GHG Emissions ....................................................................................
Land Cover within the Direct Impact Area of the Hydropower Generation and
Transmission Options....................................................................................................
Historic and Forecasted Bitumen Extraction and Upgrading Capacity in
Alberta by Operation ....................................................................................................
Historic and Forecasted Electricity Demand in Alberta by Consumption Sector .........
Electricity Intensity of Oil Sands Operations by Type of Operation .............................
GHG Emissions Intensity of Average Electricity Supply Mix in Alberta and the
Oil Sands Sector ............................................................................................................
GHG Emissions Intensity of the Oil Sands Industry and Individual Operations ............
Electric Power Demand of Oil Sands Operations by Type of Operation ......................
Currently Installed Hydropower Generation Capacity and Technical Potential
to Develop New Capacity in Canadian Provinces and Territories ................................
Overview of Hydropower Generation and Transmission Options ...............................
Alberta-BC Hydropower Generation and Transmission Options..................................
Alberta-Manitoba Hydropower Generation and Transmission Option........................
Alberta Slave River Hydropower Generation and Transmission Options ....................
Levelized Cost of Electricity Delivered to Oil Sands Operations in Alberta under
Different Generation and Transmission Options ..........................................................
Cost of Avoided GHG Emissions ....................................................................................
Capital Cost Contribution of Different Transmission System Components .................
Electricity Supply Curve ................................................................................................
GHG Emissions Abatement Supply Curve .....................................................................
Electricity Supply Curve Sensitivity Analysis against Discount Rate .............................
GHG Emissions Abatement Supply Curve Sensitivity Analysis against
Discount Rate ................................................................................................................
Sensitivity Analysis of CACO2 for Electrical Extraction Technologies ...........................
Land Cover within the Direct Impact Area....................................................................
Population and Number of Dwellings in the Direct Impact Area .................................
Number and Area of First Nations Reserve Lands in the Direct Impact Area ..............
Protected Areas and Water Bodies in the Direct Impact Area .....................................
Woodland Caribou Population in the Study Area........................................................
Land Cover of Respective Study Areas ........................................................................
Residential and Property Value Impacts ......................................................................
Impacts on Indigenous Populations .............................................................................
Protected Areas and Water Bodies within the Respective Study Areas .....................
Energy System of the SAGD Facility .............................................................................
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C.1
C.2
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Monte Carlo Simulation Results: Distributions of LCOE .............................................
Monte Carlo Simulation Results: Cumulative Distributions of LCOE ..........................
Monte Carlo Simulation Results: Cumulative Distributions of CACO2........................
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List of Tables
E.1
E.2
2.1
3.1
3.2
3.3
B.1
C.1
Summary of Hydropower Generation and Transmission Options ...............................
LCOE and CACO2 Estimates Compared to Different Reference Cases ..........................
Assumptions Made in Calculating Capital Charge Factor .............................................
Summary of Hydropower Generation and Transmission Options ...............................
LCOE and CACO2 Estimates ...........................................................................................
Minimum CACO2 and Other Metrics of Electrical Extraction Scenarios .......................
Main Parameters and Results of the Illustrative Case Example ...................................
Selected Metrics of Uncertainty Assessment Results ..................................................
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Executive Summary
The oil sands sector in Alberta is an important player in the global petroleum supply chain and a
major contributor to the provincial and Canadian economy. Extracting and upgrading bitumen is
an energy-intensive process where large amounts of thermal energy and electricity are utilized.
The energy-intensity of its operations, in addition to heightening the marginal cost of production,
have made the oil sands sector a dominant greenhouse gas (GHG) emitter in Alberta. With
growing concerns about climate change, GHG-intensive operations have created a challenging
environment for the oil sands sector. Consequently, oil sands operators and the provincial
government are exploring options to reduce GHG emissions. Decarbonizing the electricity
consumed by oil sands operations is one option to reduce GHG emissions.
Hydropower is a proven option to deliver a reliable supply of low carbon electricity. It is a major
source of electricity generation in Canada. A high potential to develop new hydropower plants
is available within Alberta and neighbouring jurisdictions. However, development of new
hydropower plants requires long distance transmission lines to connect the oil sands region to
sites with high hydropower generation potential. Furthermore, development of hydropower
plants and transmission lines can potentially have land use impacts with greater environmental
and social implications. This study identifies six options to generate and transmit hydropower to
the oil sands region in Alberta and provides a multi-attribute evaluation of those options. This
study also provides comprehensive economic assessments and high-level land use impact
evaluations. The reference electricity generation option used in this analysis is natural gas-fired
cogeneration units.
This study assesses new hydropower development options available in Alberta, British Columbia
(BC) and Manitoba. Two long distance electricity transmission technologies – high voltage direct
current (HVDC) and high voltage alternating current (HVAC) – were assessed as options to
transmit hydropower to the oil sands region. The six hydropower generation and transmission
options assessed in this report are summarized in Table E.1.
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Table E.1: Summary of Hydropower Generation and Transmission Options
Hydropower Generation Plant
Option
Site C-DC
Site C-AC
BC
Intertiei
Slave
River-DC
Slave
River-AC
Manitoba
DC
Site and River
System
Site C on the
Peace River
Site C on the
Peace River
Alternative 4
site on the
Slave River
Alternative 4
site on the
Slave River
Conawapa site
on the Nelson
River
Province
British
Columbia
British
Columbia
British
Columbia
Alberta
Rated
Capacity
(MW)
1100
1100
Increase
by 500
1100
Transmission System
Technology
No. of
Lines
Length
(km/line)
±500 kV HVDC
bipole
Single circuit
500kV HVAC
Single circuit
500kV HVAC
±500 kV HVDC
bipole
1
600
2
600
1
400
Alberta
1100
Single circuit
500kV HVAC
2
400
Manitoba
1485
±500 kV HVDC
bipole
1
1100
i
The BC Intertie option assumes a case where the existing BC-AB intertie is reinforced to import higher amounts of
hydropower purchased from the BC Hydro system. Therefore, no new hydropower plants or new transmission lines
are attributed to this option.
Source: CERI
Figure E.1 depicts the average cost of delivered electricity (taking into account both generation
and transmission cost; measured in $/megawatt hour [MWh]) under the six hydropower options.
The reference case is also shown.
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Figure E.1: Average Cost of Delivered Electricity of Different
Generation and Transmission Options
Note: All costs are in 2014 Canadian dollars.
Source: CERI
Figure E.2 shows the GHG emissions abatement cost (measured in $/tonne of carbon dioxide
equivalent [tCO2e]) of the hydropower options. GHG emissions abatement costs are calculated
in comparison to the cogeneration reference case.
Figure E.2: Cost of Avoided GHG Emissions (CACO2)
Source: CERI
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Each of these six hydropower options can deliver sufficient electricity to satisfy the demand of
in-situ bitumen extraction operations with production capacity of 0.5 million bbl/day to 1.1
million bbl/day. The average cost of delivered electricity is in the range of $81-$162/MWh.
In contrast, natural gas-fired cogeneration would cost about $57/MWh. Hence, without a price
on GHG emissions, the likelihood of hydropower options reducing the marginal cost of oil sands
operations is low. As a carbon emissions mitigation option, utilizing hydropower can potentially
reduce the GHG emissions of oil sands operations by 13-16 percent at a cost of $75-$332/tCO2e.
The lowest average cost of delivered electricity and GHG emissions abatement cost results from
purchasing hydropower from the BC Hydro system and delivering it by utilizing the existing
transmission intertie between Alberta and BC (BC Intertie option). This option requires
implementation of mitigation measures to enable the full capacity utilization of the Alberta-BC
intertie. The BC Intertie option also has the advantage of being able to deliver low GHG-intensive
electricity in the near term (within 2-5 years). Furthermore, as the BC Intertie option would
utilize existing electricity infrastructure, it would lead to zero to minimal new environmental and
social impacts.
Compared to the other new hydropower options assessed in this study, the Manitoba DC option
has a number of advantages. The Manitoba DC option has the lower average cost of delivered
electricity compared to the two new BC hydropower options. The average cost of delivered
electricity is very close to the Slave River-DC option and lower than the Slave River-AC option.
The Conawapa hydropower project, which is the generation option pertaining to Manitoba DC,
is in the advanced planning stage and Manitoba Hydro has already completed feasibility
assessments.
Hydropower generation and transmission options assessed in this study have the ability to
reduce GHG emissions of oil sands operations by decarbonizing the electricity consumed for
bitumen extraction and upgrading. However, GHG emissions from bitumen extraction and
upgrading are dominated by the emissions associated with the thermal energy portion.
Therefore, with a larger supply of hydroelectric power, it is possible to achieve deeper emissions
in the oil sands sector by deploying electrical extraction technologies for in-situ recovery of
bitumen.
The reference case used in this analysis is onsite cogeneration. Adding onsite cogeneration to an
oil sands operation requires additional investments and increases operational complexity.
Therefore, it is also plausible that the oil sands operators may choose to purchase electricity from
the Alberta electricity market, instead of onsite generation. In that situation, the reference case
could be the grid average cost and emissions of an average price of $66/MWh and higher
emissions of 710 KgCO2/MWh. The reference case could also be the highest emissions source –
coal-fired generation – using a coal-based electricity price of $83/MWh and emissions of 820
KgCO2/MWh. This latter option is being phased out in Alberta but still forms a plausible reference
case to compare displacement costs. If these six hydroelectricity options were considered, the
carbon emissions abatement cost changes as shown in Table E.2.
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Table E.2: LCOE and CACO2 ($/tCO2e) Estimates Compared to Different Reference Cases
Site C-DC
LCOE
CACO2 – Cogen
CACO2 – Grid Avg.
CACO2 – Coal
141
266
107
72
HVDC Options
Slave
Manitoba DC
River-DC
110
124
165
207
62
82
33
50
HVAC Options
Intertie Option
Site C-AC
Slave River-AC
BC Intertie
162
332
137
98
121
198
77
47
81
75
21
-3
Source: CERI
Abatement costs are sensitive to the reference case. For the situation replacing new coal-fired
generation with the BC Intertie, the abatement cost is negative because the cost of BC-intertie
electricity is less than coal-based generation.
Figure E.3 depicts the land cover within the direct impact area of the hydropower generation and
transmission options. In this study, the direct impact area is defined as the area formed by a
combination of a 1 km wide buffer that encloses the selected transmission line corridor and a
circular buffer with a 10 km radius that encloses the hydropower plant.
Figure E.3: Land Cover within the Direct Impact Area of the Hydropower Generation and
Transmission Options
Source: CERI
As depicted in Figure E.3, due to the greater transmission distance, the Alberta-Manitoba option
(Manitoba-DC) has the highest land use impact while the shorter transmission distance makes
the Alberta hydropower options (Slave River-DC/AC) the ones with the lowest land use impacts.
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However, careful assessment of the land cover reveals some interesting findings. Of the new
hydropower options, the Alberta-BC options (Site C-DC/AC) have the highest agricultural and
residential (in terms of populated areas within the direct impact area) impacts. Despite the longer
transmission distance, the Alberta-Manitoba option has the lowest residential impacts. In all
cases, the majority of the populated areas that would be impacted by new hydropower options
are within Alberta. Alberta Slave River options would likely have the highest amount of
environmental impacts in terms of the environmentally sensitive areas within the direct impact
area. Environmental impacts could be exacerbated by potential impacts on the Wood Buffalo
National Park and the Peace-Athabasca Delta, a wetland ecosystem with global significance.
Moreover, these two options would have the highest impacts on aboriginal populations in terms
of the number of First Nations reserves within the direct impact area.
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Chapter 1
Introduction
Oil sands deposits in northern Alberta is a nationally important hydrocarbon reserve. At a total
reserve estimate of 173 billion barrels of oil equivalent (BOE) at the end of 2014, it is the third
largest proven hydrocarbon reserve in the world, behind Venezuela (298 BOE) and Saudi Arabia
(267 BOE) (BP, 2015). In 2014, total capital investments in the oil sands industry amounted to
CDN$24.3 billion, which was 26 percent of total capital investments in Alberta and 7 percent that
of Canada (Alberta Government, 2015; CAPP, 2015b). The enormous amount of capital
investments as well as technological developments has led to steady growth in bitumen
extraction from oil sands and upgrading it into synthetic crude oil.
According to the Alberta Energy Regulator (AER), at the end of 2014, production capacity of oil
sands crude1 was 2.2 million barrels per day (bbl/d) (AER, 2015). Oil sands crude production
capacity is expected to rise to 5.8 million bbl/d by 2030 (Murillo, 2015). The capital investments
and operations of the oil sands sector contributes to economic growth in Canada, creates jobs,
and drives the growth in other sectors of the economy such as manufacturing, transportation,
financial, professional services, etc. (CERI, 2011).
The main hydrocarbon product that is being extracted from the oil sands is bitumen, a heavy,
highly viscous form of petroleum that does not flow at normal reservoir conditions (Charpentier
et al., 2011). Consequently, unconventional and advanced extraction techniques are being
applied to recover and extract bitumen from oil sands deposits and upgrade bitumen into
synthetic crude oil (SCO).2 Bitumen is extracted from the oil sands deposits through surface
mining or through in-situ extraction techniques (Murillo, 2015). The two main in-situ techniques
currently being employed are steam assisted gravity drainage (SAGD) and cyclic steam
stimulation (CSS).
Figure 1.1 depicts a long-term forecast of bitumen production and upgrading levels in Alberta by
type of operation as estimated in a recent CERI study (Murillo, 2015; Business as Usual scenario).
Recent economic conditions, particularly lower oil prices, may potentially lead to a lower
production growth rate than the ones depicted in Figure 1.1. For example, a recent outlook by
the Canadian Association of Petroleum Producers (CAPP) estimates the total bitumen extraction
level in 2030 to be approximately 800,000 bbl lower than that of the level depicted in Figure 1.1
(CAPP, 2015a). The production level, nonetheless, is forecasted to grow steadily from current
levels.
Due to intense processing requirements, bitumen extraction and upgrading are energy-intensive
operations (Bergerson et al., 2012; Englander et al., 2015; Nduagu & Gates, 2015). In general,
1
2
This includes both upgraded and non-upgraded bitumen
As of 2014, approximately 31% of bitumen is upgraded into synthetic crude oil (AER, 2015).
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energy demands for oil sands projects can be divided into three categories: thermal energy
demand, which is primarily satisfied through combustion of natural gas; electricity demand; and
demand for transportation fuels (such as diesel fuel) (Murillo, 2015). Natural gas is the primary
feedstock to produce hydrogen (H2) used for bitumen upgrading.
Figure 1.1: Historic and Forecasted Bitumen Extraction and
Upgrading Capacity in Alberta by Operation
Source: Business as Usual (BAU) scenario, CERI Study 151 (Murillo, 2015)
With the rapid growth of oil sands operations, the oil sands sector has become a dominant
consumer of primary energy in Alberta. For example, in 2014 the oil sands sector accounted for
30 percent of natural gas use, 20 percent of diesel fuel use, and 21 percent of electricity use in
Alberta (Murillo, 2015). The fossil fuel dependence of the oil sands sector3 has also led to a
significant amount of GHG emissions as well. In 2013, GHG emissions resulting from oil sands
operations was 61.4 metric tons of carbon dioxide equivalent (MtCO2e), which was 23 percent of
Alberta’s emissions and 8 percent of Canadian emissions (Environment Canada, 2015a).
3
Natural gas for thermal energy; natural gas, coal, and petroleum coke for electricity production within the oil
sands sector and Alberta grid; and diesel for transportation
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With growing worldwide concerns about GHG emissions, the oil sands sector has been put under
scrutiny. Current and future provincial (Government of Alberta, 2015) and national climate
change mitigation policies as well as policies or regulations in other jurisdictions, for example,
California’s Low Carbon Fuel Standard (CARB, 2015), can potentially influence oil demand.
Mounting concerns about the sector’s GHG emissions, and other associated environmental
(Gosselin et al., 2010) and public health impacts (Kelly et al., 2009; McLachlan, 2014) has created
a challenging environment for the oil sands sector both locally (ACFN, 2015; Droitsch &
Simieritsch, 2010) as well as internationally (McCarthy, 2014). Consequently, options are being
explored to reduce greenhouse gas emissions and other environmental impacts through fuel
switching, energy efficiency and process improvements.
Oil Sands Electricity Demand and the Opportunity to
Reduce GHG Emissions
Extracting and upgrading bitumen requires large amounts of electricity. As such, oil sands
operations require a reliable supply of electricity. According to the Alberta Electric System
Operator (AESO) the total share of electricity consumed by the oil sands sector is expected to rise
to 30 percent of total provincial electricity demand by 2022 (see Figure 1.2) (AESO, 2014a).
Consequently, decarbonizing the electricity consumed by oil sands operations is one option to
reduce GHG emissions.
Figure 1.2: Historic and Forecasted Electricity Demand in Alberta by Consumption Sector
Source: Data from AESO (2014); figure by CERI
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Advancements in electricity generation, transmission, distribution, and storage have provided
many technically and commercially feasible options to produce and deliver low carbon electricity
(IEA, 2014). These options include generating electricity using low or zero carbon-intensive
technologies such as renewable power sources, nuclear power, and use of carbon capture and
storage (CCS) in fossil fuel-fired power plants, reducing transmission and distribution losses, and
the use of storage systems for optimal electricity supply and demand matching.
Electricity is a very versatile form of energy that can provide virtually any end use energy service.
Unlike many other energy carriers, conversion of electricity into end use energy services can be
done at very high efficiencies. Furthermore, the marginal cost of reducing carbon emissions in
the electric power sector is reported to be lower than other sectors such as the industrial and
transportation sectors (Apt, Keith, & Morgan, 2007). All of these factors have made widespread
electrification of energy end use services a driving force across the global energy system (IEA,
2014).
Hydropower is a proven option to deliver a reliable supply of low carbon electricity. It is a major
source of electricity generation in Canada. More than 60 percent of current electricity supply in
Canada is produced using hydropower plants (Statistics Canada, 2015). The total installed
hydropower capacity in Canada amounts to 76 GW (approximately 58 percent of total Canadian
power generation capacity). In addition to providing a clean and reliable supply of electricity, the
hydropower industry is a significant contributor to the Canadian economy. In 2013, the
hydropower industry contributed CDN$37 billion to Canada’s gross domestic product (GDP) and
supported 135,000 full time equivalent (FTE) jobs4 (PRISM Economics and Analysis, 2015).
Decarbonizing electricity supply by utilizing hydroelectric energy can potentially reduce the
overall GHG emissions from oil sands operations. Figure 1.3 depicts the electricity demand of
different oil sands operations (measured in kWh per barrel of output, kWh/bbl). Currently, these
electricity demands are being satisfied by a mixture of electricity sources. A vast majority of
bitumen and SCO are being produced by projects that have onsite electricity generation. The
main source of onsite generation is natural gas-fired cogeneration, where high fuel efficiencies
are achieved by co-producing electricity and thermal energy (Doluweera et al., 2011). While
natural gas is the primary fuel, some projects use petroleum coke as a fuel for cogeneration.
4
As estimated by PRISM Economic Analysis (2015), job contribution includes direct, indirect, and induced effects.
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Figure 1.3: Electricity Intensity of Oil Sands Operations by Type of Operation
Source: CERI Study 151 (Murillo, 2015); Note the logarithmic scale in the y-axis
Projects that do not have cogeneration, purchase electricity from the Alberta grid. A large
fraction of electricity in Alberta is produced using coal-fired generating units5 resulting in a higher
average GHG emissions intensity. However, the Alberta provincial government has recently
announced coal plant retirements so it is uncertain if any existing plants will be operating post2030 (AESO, 2014a; Murillo, 2015).
Figure 1.4 depicts the average GHG emissions intensity of the average Alberta grid mix and that
of the electricity mix of the oil sands sector.6
5
In 2014, coal-fired generating units produced 65% of electricity production. This excludes behind the fence
power generation that served onsite demands (AESO, 2015a).
6
Alberta grid mix intensity is estimated by taking into account the current generation mix, unit retirements, and
most likely future additions. Oil sands electricity emissions intensity is estimated by taking into account the onsite
generation fuel mix and electricity import volumes from the grid.
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Figure 1.4: GHG Emissions Intensity of Average Electricity Supply Mix in
Alberta and the Oil Sands Sector
Source: CERI Study 151 (Murillo, 2015).
Figure 1.5 shows GHG emissions intensity of the oil sands industry and individual operations. By
synthesizing the information presented in Figures 1.3-1.5, it can be seen that the use of low
carbon hydropower7 to satisfy electricity demands leads to GHG emissions reductions. For
example, in 2025, the use of hydropower can reduce GHG emissions of mining operations by 16
percent and for in-situ operations by 13 percent (for SAGD)8 to 15 percent (for CSS).
7
Although no direct GHG emissions result from hydropower generation, a very low amount of life cycle GHG
emissions is associated with hydropower due to construction phase emissions and emissions from lacustrine
conditions created by altering riverine systems by hydropower dams (PNNL, 2013). Those indirect leads to an
emissions intensity that is in the order of 3-10 kgCO2 eq/MWh.
8
For example, SAGD operations require about 16.5 kWh of electricity per barrel of bitumen. The estimated
(Murillo, 2015) GHG emissions intensity of in-situ operations (including both SAGD and CSS) in 2025 is 72 kgCO2
eq/bbl. Oil sands electricity emissions intensity in 2025 is 0.55 kgCO2/kWh. Therefore, use of hydroelectric power
results in an emissions reduction of 9 kgCO2/bbl (= 12.5% of 72 kgCO2 eq).
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Figure 1.5: GHG Emissions Intensity of the Oil Sands Industry and Individual Operations
Source: CERI Study 151 (Murillo, 2015).
In addition to prevailing bitumen extraction technologies, it is also possible to extract bitumen
using electrical extraction technologies. In these cases, electricity is utilized as the primary
energy source, excluding the use of steam produced through fuel combustion. To date, two
innovative electrical extraction processes have been demonstrated in Alberta. One
demonstration project is based on a process called Electro-Thermal Dynamic Stripping Process
(E-T DSP™) where electrical current passes between electrodes through a water envelop that acts
to heat the bitumen (McGee, 2012).
A second experimental project is based on a process called Effective Solvent Extraction
Incorporating Electromagnetic Heating (ESEIEH). The ESEIEH process eliminates the use of water.
Bitumen is concurrently heated with electrical energy and further diluted with the injection of a
solvent in a gravity drainage recovery process (Patterson, 2015). If a low/zero GHG emissive
electricity supply, such as hydropower is available, it is possible to extract bitumen with negligible
amounts of GHG emissions.
Hydroelectric Power Generation Options
Hydroelectricity is produced by harnessing the energy in flowing water through turbines. There
are two types of hydroelectric power plants: 1) plants with a storage reservoir that use a dam to
store water and discharge to produce electricity; and 2) run-of-river (ROR) plants that do not use
a dam but divert the river to flow it through turbines. In the case of ROR plants, the operators
have limited control over the level of electricity production, as the plant relies on the natural flow
of the river it has tapped. There are modified run-of-river plants that rely on the flow of water
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to produce electricity and store water using a smaller reservoir to gain more control over the
level of production.9
Hydroelectric plants generally have a long operational life that is in the order of 60 to 100 years.
Therefore, once developed, a hydroelectric plant can provide a clean reliable supply of electricity
for a long period.
As depicted in Figure 1.6, within 10 years, the electric power demand of oil sands operations
could rise to 3,500 MW, which is approximately 1,400 MW beyond current demand. This only
includes the direct electricity requirements of oil sands operations and does not take into account
the electricity demand growth due to higher induced economic activities. Even under the lower
oil sands growth as forecasted by CAPP, the direct electricity demand of oil sands operations will
likely grow over 1,000 MW (Murillo, 2015).
Only about 3 percent of Alberta’s electricity is currently produced using hydropower and the total
installed hydropower production capacity is only 890 MW (AESO, 2015a).
Figure 1.6: Electric Power Demand of Oil Sands Operations by Type of Operation
Source: CERI Study 151 (Murillo, 2015).
9
For example, maintaining reservoir will allow the operator to produce more electricity than the amount allowed
by the water flow. This controllability can potentially be a valuable attribute of the plant when satisfying time
varying electricity demand.
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Figure 1.7 depicts the currently developed hydroelectric capacity and technical potential to
develop new capacity (Irving, 2013). As can be seen from the figure, there is significant
hydropower potential available in Alberta and neighbouring jurisdictions. As estimated by the
Canadian Hydropower Association, new hydropower development potential in Alberta is about
11,800 MW (Irving, 2013).
Prince Edward Island has a technical potential of 3 MW, which is not shown in the figure. The
values indicated in the figure correspond to hydropower production capacity (measured in MW).
The energy production capacity (measured in MWh in a given time period) depends on river flow
rates and precipitation levels in the period of interest.
Figure 1.7: Currently Installed Hydropower Generation Capacity and Technical Potential to
Develop New Capacity in Canadian Provinces and Territories
Source: Canadian Hydropower Association (Irving, 2013).
Another assessment made by HATCH (2010) for the Alberta Utilities Commission (AUC) estimated
Alberta’s new hydroelectric energy potential to be 53,000 GWh/year. The HATCH assessment
identified 36 sites10 suitable for hydroelectric power development in three northern river basins.
The single site on the Slave River, near the border between Alberta and NWT has the highest
capacity potential (up to 1,500 MW) and energy potential (8,500 GWh/year). The feasibility to
develop a hydropower plant on the Slave River has been investigated by both the Alberta
10
Seventeen on the Athabasca River, eighteen on the Peace River, and one on the Slave River.
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government and private investors since 1980 (ATCO Power & TransCanada, 2009; Legislative
Assembly of Alberta, 2013; SRSC, 1980).
The neighbouring jurisdictions of British Columbia (BC), Saskatchewan (SK), the Northwest
Territories (NWT), and Manitoba (MB) have a combined potential of 57,400 MW to develop
hydropower plants.
Although a large amount of hydroelectric potential has been reported within Alberta and
neighbouring jurisdictions, the feasibility to tap into that potential depends on economic, social,
and environmental factors.
Development of hydropower generation capacity is very capital-intensive and the development
cost is site sensitive. According to the International Energy Agency (IEA), the capital cost of large
(larger than 10 MW) hydropower plants ranges from US$1,750/kW to US$6,250/kW11 (IEA ETSAP,
2010). However, the operational costs are very low (in the order of 1.5 percent to 2.5 percent of
the investment cost per year). On a per kW basis, the capital cost of plants with smaller capacities
can be several times higher than that of larger plants. As such, the cost of energy produced by
hydroelectric plants is dominated by its capital cost. Therefore, for a hydroelectric plant to be
economically feasible, it must have the ability to operate at a high capacity factor (cf).12
A larger fraction of the capital cost of a hydroelectric power plant has to be spent on items that
are disproportionate to the nameplate capacity of the power; for example, on planning,
feasibility studies, permitting, environmental impact assessments and access roads.
Furthermore, the magnitude of some environmental and social impacts such as impacts on
natural ecosystems, fishery, and involuntary relocation of people tend to be disproportionate to
the capacity of the plant. Therefore, developing the full capacity of a given site leads to more
favourable economics than partial development.
Sites with good hydroelectric potential tend to be in remote areas away from major demand
centers, requiring new transmission lines to connect them. Transmission development is also
capital-intensive. Therefore, it is important that high capacity factors be maintained to keep
transmission costs low. Furthermore, due to the amount of transmission requirements, if
sufficient demand is available, developing larger sites with high capacity factors leads to lower
overall costs than developing several smaller sites.
In the case of identifying hydroelectric power supply options for oil sands operations, it is
important that they have the ability to supply large amounts of economically priced electric
energy with high reliability. As such, although higher amounts of hydroelectric potential have
11
Values are in 2008 US$
The capacity factor is the ratio between a power plants actual output in a given time period (usually a year) to its
poetical output if the plant was continuously operated at its full nameplate capacity over the same period, i.e.,
cf=(power generation in MWh)/(nameplate capacity in MW x no. of hours in the period in h)
12
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been reported, only a limited number of sites possess the necessary attributes. This is further
discussed in Chapter 2.
Transmission Options to Move Hydropower
Sites with good hydroelectric potential tend to be in remote locations. For example, sites that
are suitable to develop a hydropower plant on the Slave River are approximately 400 km north
of the region where oil sands operations are concentrated. Therefore, new long distance
transmission lines are required to connect them.
The Alberta electric power system currently has limited transmission interconnections with
neighbouring jurisdictions. Therefore, in order to import larger amounts of hydropower into
Alberta, new transmission interconnections need to be developed.
Electricity is generated, transmitted, and most of the time utilized in the form of alternating
current (AC). The other form is direct current (DC) electricity, where the flow of electric charge
is in one direction. In AC systems the electric current (or electric charge) periodically changes
direction. The period at which the current changes its direction is known as the system
frequency.13 The way electricity is generated and transmitted has led to the dependence on AC
electricity. The majority of large-scale power generating plants utilize rotating machines that are
driven by a prime mover,14 taking advantage of electromagnetic induction. These rotating
machines essentially produce electricity in AC form.
The most important reason for the dominance of AC is the fact that it enables the use of
transformers to increase the voltage at which electricity is transmitted and then decreases it back
to distribution/utilization voltages.15 Use of higher voltages minimize transmission losses that
incur when electric current passes through a conductor.16 As a result, the most prevalent form of
electricity transmission is high-voltage alternating current (HVAC) that utilizes voltages higher
than 115 kilovolts (kV).
In some situations, however, use of a high voltage direct current transmission system (HVDC) is
beneficial and the preferred choice.17 The primary reason for this is that HVDC eliminates the
problem of a stability limit of a transmission system.
13
In North America, the AC system frequency is 60 cycles per second or 60 Hertz (Hz).
For example, water turbines in the case of hydropower plants, steam or gas turbines in the case of thermal
power plants, wind turbines in the case of wind farms, etc.
15
Transformers also rely on electromagnetic induction and only work off AC electricity
16
Amount of power transmitted (Pt) through a conductor is equal to the product of the voltage difference (V) at
which power is transmitted and the electric current (I). i.e., P t=VI. Consequently, for a given amount of power,
increasing the voltage leads to lower current. Power loss in the form of heat in the transmission wire (P l) is equal
to the product of the resistance of the wire (R) and the square of the current (i.e., P l=I2R). For a given transmission
line, the cable resistance is proportional to the length of the conductor. Hence, lowering the current reduces
transmission losses.
17
Detailed technical and other relevant descriptions about different transmission technologies can be found in the
following reports that are in the public domain: (Simens, 2013; Stantec, 2009).
14
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AC current changes its direction at the system frequency. The frequency is directly linked to the
rotational speed of the generators. It is important that all generators in a given electric power
system are in sync with each other and producing AC electricity within a very narrow margin
around the system frequency. Speeding up or slowing down of a certain generator impacts other
generators. Stability of an electric power system then refers to its ability to maintain the
synchronism among the generators.
In addition to the resistance, long HVAC transmission lines have a significant reactance.18 Beyond
a certain length, the system’s ability to maintain the synchronism among the generators that are
at either end of the lines becomes challenging due to the high reactance. This limit is known as
the stability limit of an HVAC line, and it can be significantly lower than the thermal limit
(determined by the resistance of the line). In the case of HVDC lines, since reactance is irrelevant,
the line can be utilized up to the thermal limit of the conductors, enabling more power
transmission within a comparably sized transmission corridor.
Transmission loss in HVDC lines and electrical cable cost can be lower than HVAC lines with
comparable length and capacity. An HVAC transmission line generally transmits power in three
phases and therefore requires three conductor bundles.19 In the case of HVDC, the same amount
of power can be transmitted with only one single or two conductor bundles. Reduction in the
number of conductor bundles lowers the cost and losses.
Despite these benefits, a few challenges limit the widespread use of HVDC for long distance
transmission. As discussed, generation and utilization of electric power is done in AC form.
Furthermore, electrical transformers that work only off AC are required to elevate the voltages
to levels suitable for transmission. Therefore, a HVDC transmission system requires two
additional components to convert AC to DC (this converter is called a rectifier) at the sending end
and then back to AC (using an inverter) at the receiving end. These converters add a significant
amount to the capital cost of the system.20 Due to the high cost of converters at the sending and
receiving ends, intermediate taps to a HVDC line may not be economically feasible, essentially
making it a point-to-point transmission option. Furthermore, these additional system
components add more losses (in the order of 1 percent) and reduces the reliability.
As the transmission length increases, the cost impact of the converter to the overall project cost
is reduced. This makes the HVDC option more economic for longer transmission lines (Gavriovic,
2003; Simens, 2013; Stantec, 2009). For example, at a distance of 600 km, the transmission cost
(measured in $/MW-km) of a single circuit 500 kV HVDC line is 19 percent lower than that of a
18
Reactance is proportional to the inductance of the line and the frequency at which power is flown through the
conductor. For DC, since there is no change in the direction of current (i.e., frequency is zero), reactance is
irrelevant (von Meier, 2006).
19
Generally a bundle of three conductors.
20
In the order of $300-500 million or 25% or more of the total project cost.
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500 kV HVAC line. In Canada, Manitoba Hydro and Hydro Quebec have significant experience in
utilizing HVDC lines to move hydropower.21
Due to the geographic separation between the oil sands region and good sites to develop new
hydropower plants, HVDC can potentially be the more suitable transmission option. However,
both AC and DC options are considered in this paper.
Scope and Objectives
The energy-intensity of oil sands production contributes to the higher than average marginal cost
of production and GHG emissions intensity. With the climate change imperative, GHG-intensive
activities have drawn criticism, including bitumen production. Using hydroelectric power to meet
oil sands electricity demand can potentially provide an option to reduce GHG emissions.
Furthermore, despite the high initial cost, the lower operating cost and long operational life of
hydropower plants and associated transmission lines can potentially reduce the cost of
electricity.
The main objective of this report is to identify hydroelectricity options that would reduce GHG
emissions in oil sands production.
Despite the economic and societal benefits provided by large hydroelectric infrastructure
projects, there is opposition to these projects due to stakeholder concerns of land use and water
impacts and as a result permitting and siting them has become increasingly difficult (Schively,
2007; Vajjhala & Fischbeck, 2007). Project attributes that lead to such difficulties include complex
social and environmental implications. In general, public opposition arises from concerns related
to unwanted interference with private property rights, environment degradation, and Indigenous
peoples traditional uses.
This report, therefore, provides a multi-attribute evaluation of the hydropower and transmission
options by quantifying the economic, social, environmental, and land use impacts. Such multiattribute evaluations provide investors, Indigenous Peoples, non-governmental organizations,
regulators, and policy-makers useful insights into costs and benefits of different options. Having
a common understanding of the attributes of a project facilitates stakeholder discussions and
can contribute to effective decision making.
The specific contributions of this report are as follows:
1. Identify six options to produce and deliver hydroelectric power to satisfy electricity demands
of oil sands operations;
2. Provide economic assessments of those six options;
21
In Manitoba, two ±500 HVDC lines known as Bipole I & Bipole II transmit power from hydropower plants on the
Nelson River in northern Manitoba to Winnipeg, the main demand center. In Quebec, a ±450 HVDC line (known as
Radisson - Nicolet - Des Cantons circuit) moves hydropower from Northern Quebec to southern parts of the
province as well as to New England (US).
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3. Estimate GHG emissions reduction potential and GHG emissions abatement costs of those six
options;
4. Provide a preliminary economic assessment and GHG abatement cost of electrical extraction
of bitumen with hydroelectric power; and
5. Provide an assessment of land use, social, and environmental impacts of those options using
publicly available data sets.
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Chapter 2
Methodology
Hydropower Generation Options
Figure 2.1 provides an overview of the generation and transmission options for hydropower
generation.
Figure 2.1: Overview of Hydropower Generation and Transmission Options
Source: CERI
As discussed in Chapter 1 (and depicted in Figure 1.7), hydropower potential is available in
Alberta and neighbouring jurisdictions (Irving, 2013). Specific information about those sites are
available in the public domain (BC Hydro, 2013a; Government of the Northwest Territories, 2011;
HATCH, 2010; Manitoba Hydro, 2013; SaskPower, 2010). In order to narrow down the sites to be
analyzed in this study, the following factors are taken into account.

Oil sands operations require large quantities of electricity that is reliably supplied with
minimal variation. Therefore, the potential hydroelectric sites need to have both higher
production capabilities and capacity factors. This study considered only sites with higher
than 500 MW of technical potential that can be operated at an average capacity factor of
50 percent or more.1
1
The equivalent energy supply potential is 2,190 GWh/year or more. Based on (Murillo, 2015), 2,190 GWh of
electricity is sufficient to satisfy the electricity demand of a SAGD facility with a bitumen production rate of
approximately 360,000 bbl/day.
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



As new transmission lines need to be constructed to connect potential hydropower
plants, this study examines only hydropower potential available in Alberta, British
Columbia and Manitoba.
Developing several geographically dispersed hydropower plants with relatively smaller
capacities was not considered as an option because that would lead to higher
transmission costs and cumulative environmental impacts. Developing a single
hydropower plant also enables the use of a single HVDC transmission line, which is
essentially a point-to-point transmission option.
Significant hydropower potential is reported to be available in the Northwest Territories
(NWT). However, that was not considered for this study due to the unavailability of
reliable resource data and potentially longer transmission distances. Furthermore, the
hydropower potential available on the NWT side of the Slave River is shared with Alberta.
Saskatchewan is reported to have relatively smaller hydropower potential (SaskPower,
2010). The reported sites are geographically dispersed and have smaller technical
potential (250 MW or lower). Therefore, hydropower potential in Saskatchewan is
excluded from this study.
Hydropower Generation Options in Alberta
The main data source used to assess Alberta’s hydropower potential is an assessment conducted
by HATCH (2010) for the Alberta Utilities Commission. The HATCH report provides an assessment
of hydropower potential in five main river basins of Alberta. Of the five basins, only the Peace,
Athabasca, and Slave River basins appear to have the energy potential that meets the selection
criteria. A limited amount of information – such as geological viability of sites, cost estimates –
is available for the sites in the Peace and Athabasca River basins.
TransAlta, a major utility company in Alberta, has been allowed to develop a hydropower plant
at the Dunvegan site on the Peace River. However, that was excluded as the available capacity
is reported to be only 100 MW. Furthermore, new hydropower developments in the BC section
of the Peace River – mainly the Site C project – may constrain the capacity available on the Alberta
section. A number of sites that are suitable for hydropower plants have been identified in the
Athabasca River basin, of which some are closer to Fort McMurray. All have relatively low annual
hydroelectric generation potential and were excluded from the study based on the selection
criteria.
After taking into account those factors, only the hydropower potential available on the Slave
River was selected for this study. The Slave River is formed where the Peace River meets the
Riviere des Rochers and the river terminates upon flowing into Great Slave Lake in the NWT. Just
south of the Alberta-NWT border, the Slave River enters a series of rapids known as Smith Rapids;
a 30 km reach caused by the outcrop of the Canadian Shield. The hydropower potential within
these rapids has been recognized for many years. The average flow rate of the Slave River, within
the rapids near Fort Fitzgerald, is about 3,440 m3/s, which is by far the highest flow level of any
river in Alberta (HATCH, 2010). Annual flow variation of the river is relatively low due to the
natural regulation provided by Lake Athabasca and reservoir regulation by the W.A.C. Bennett
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Dam in BC. The high and steady flow rates enable development of a hydropower plant with
limited or no storage capacity.2
An extensive study of the hydropower potential including exact site identification, geological
assessments, detailed cost assessments, and transmission options (SRSC, 1980) was conducted
by the Alberta Government in the early 1980s. Upon exploring many options, that assessment
identified three sites to develop a hydropower plant: Mountain Rapids site and Alternative 4 Site
(A4S) in Alberta and Rapids of the Drowned in the NWT (see Figure 2.1). A4S has been identified
as the most suitable site. ATCO Power and TransCanada, two energy companies in Alberta, are
currently exploring the potential to develop a hydropower plant, likely at the A4S (ATCO Power
& TransCanada, 2009). The project did not proceed to the feasibility assessment stage due to the
opposition of the Smith’s Landing First Nations (Bell, 2010). AESO has included transmission lines
to connect a hydropower plant on the Slave River in its long term transmission plan (AESO,
2014b), indicating the continued interest in this site.
The hydropower potential at the A4S is estimated to be as high as 1 500 MW. Annual flow rates
and energy potential at A4S were obtained from (HATCH, 2010; SRSC, 1980) and also cross
validated by using recent flow rate data (Environment Canada, 2015c). Upon assessing this data,
the hydropower plant capacity at A4S is set to be 1,100 MW. With observed historic annual flow
rates, the average capacity factor is estimated at 68 percent.
Additional hydropower opportunities are available within Alberta in the form of expanding the
capacity of existing hydropower plants. This option is likely more economically preferable than
building new hydropower plants. However, based on available information (HATCH, 2010), the
incremental hydropower potential is lower than 500 MW and therefore did not satisfy the
screening criteria used in this study.
Hydropower Generation Options in British Columbia
Remaining hydropower resource potential in BC amounts to a staggering 32,000 MW. The vast
majority of this capacity, however, is suitable only for ROR hydropower plants with limited
dependable capacity (BC Hydro, 2013a; Appendix 8-A).3 Options to develop hydropower plants
with high dependable capacity in BC are limited to Site C on the Peace River and adding additional
turbines to existing but unused bays of some existing hydropower plants. Two main options in
the latter category are the Mica units 5 and 6 and Revelstoke unit 6. Currently BC Hydro is
installing Mica units 5 and 6 that have a combined capacity of 1,000 MW. Revelstoke unit 6 is in
the active planning stage and has a potential capacity of 500 MW (BC Hydro, 2008).
The Site C dam and the associated generating station is a 1,100 MW hydropower plant that is
now under construction. The power plant is estimated to have an annual energy generation
2
i.e., either as a ROR plant or modified ROR plant.
According to BC Hydro’s 2013 integrated resource plan, due to limited energy potential, the estimated average
cost of generation at a larger number of sites, with a cumulative capacity of approximately 12,000 MW, is more
than $200/MWh.
3
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Canadian Energy Research Institute
potential of 5,100 GWh. Construction of the project started in summer 2015 and is expected to
be completed in 2024. It is the third hydropower plant on the BC segment of the Peace River.
The proposed site is approximately 7 km southwest of the town of Fort St. John, BC. The length
of a direct transmission interconnection to the oil sands region is approximately 600 km.
Two BC hydropower options are assessed in this study:
1) Site C generating station with a direct transmission link to the oil sands region.
2) Buying hydropower from the BC grid and transmitting it using the Alberta-BC
interconnection. In this case, the source of hydropower could potentially be BC’s legacy
hydropower system and new turbine additions to unused bays of existing hydropower
plants. In order to import higher amounts of hydropower from BC, the existing
transmission intertie between Alberta and BC needs to be reinforced to utilize its full
capacity (AESO, 2015b).
Hydropower Generation Options in Manitoba
Manitoba is a major hydropower producer and exporter. Approximately 98 percent of
Manitoba’s 5,485 MW power generating capacity is composed of hydropower plants. About 30
percent of electricity produced in Manitoba is exported to other provinces and to the United
States, making electricity export revenues an important contributor to the province’s economy.
Remaining hydropower potential in Manitoba is estimated to be 8,800 MW (Irving, 2013). Due
to greater transmission developments required to connect to the oil sands region in Alberta
(more than 1,000 km), only potential sites in Manitoba with high dependable hydropower
capacity are considered for this study.
In an assessment of resource options to develop new power generation capacity in the province,
Manitoba Hydro identified 16 new hydropower options (Manitoba Hydro, 2013; Appendix 7.2).
Of those options, the proposed Keeyask generating station (695 MW) and Conawapa generating
station (1,485 MW) are reported to have the lowest average cost of production. Both sites are
on the Nelson River in northern Manitoba and are reported to have the ability to operate at
relatively high capacity factors.4 The Manitoba Public Utilities Board has approved the Keeyask
generating station for construction. Construction of Keeyask generating is required to satisfy
future demand growth of Manitoba and Manitoba Hydro’s electricity export contractual
obligations. Consequently, it is uncertain whether capacity of Keeyask would be available to
export to Alberta. Therefore, the proposed Conawapa generating station is assessed in this study
as the hydropower import option from Manitoba.
The Conawapa power generation project is in the advanced planning stage and therefore reliable
resource and cost estimates are available from Manitoba Hydro. Straight-line transmission
distance between the proposed site for the Conawapa project and the oil sands region is 1,100
km. It should be noted that this distance is in the same order as the length of HVDC transmission
4
80 percent for Keeyask and 57 percent for Conawapa.
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lines that transmit power from hydropower generating stations on the Nelson River in northern
Manitoba to demand centres and export terminals in Winnipeg.5
Transmission Options
Transmission options that are assessed in this report are selected taking into account technical
constraints (such as transmission losses, reliability, frequency variation, and system stability) and
cost. Both HVDC and HVAC transmission options are assessed for Slave River (Alberta) and Site
C (BC) hydropower options. For Conawapa (MB), only HVDC transmission options are considered.
One main reason for that is Manitoba and Alberta are in different interconnections6 of the North
American electric power system. An interconnection is a regional entity where the individual
power systems in given interconnections coordinate their operations to ensure system reliability.
Any intertie between two separate interconnections must be asynchronous (i.e., must utilize DC
links) so that any frequency variation and contingency in one interconnection will not affect the
stability of the other. Therefore, HVAC options are not considered for the Conawapa option.
All transmission options are assumed to operate at 500 kV. HVDC options are assumed to
operate ±500 kV bipole mode with ground return. Bipole mode has higher reliability as the HVDC
line can be operated at half the capacity even if a contingency occurred in one pole (Gavriovic,
2003; Simens, 2013).
Due to the large amount of power being transferred through the transmission corridor, to
increase system reliability, a given HVAC interconnection is assumed to be composed of two
single circuit 500 kV HVAC lines.7 This is consistent with transmission options explored by AESO
to interconnect a potential hydropower plant on the Slaver River (AESO, 2014b). The amount of
power transmitted through an HVAC line can be increased by adding series capacitors (also
known as series compensators) to increase the stability limit. However, no series compensation
is assumed for HVAC options in this study as sufficient capacity is available between two 500 kV
single circuit lines.
All transmission systems are assumed to have static VAR (SVAR) compensators at the receiving
end for reactive power compensations.
Capital costs of transmission lines, substations, compensating devices, land, and construction are
calculated by utilizing a tool developed by Black & Veatch (2014) for the Western Electricity
Coordinating Council (WECC). The tool has been reviewed by transmission line siting
professionals from various electric power systems within the Western interconnection.
Transmission losses are also estimated using this tool.
5
The two HVDC transmission systems are 895 km and 937 km in length.
Alberta is in the Western Interconnection and Manitoba in the Eastern Interconnection
7
Two lines would provide the system operator added reliability as a contingency on a single corridor but would not
completely disconnect the hydropower plant from the system
6
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Selection of Transmission Line Corridors
For all transmission options, Fort McMurray, Alberta has been selected as the receiving end
terminus point. Sending ends are the respective hydropower generating sites. Selection of exact
transmission right of way (ROW) is a complex process that requires extensive surveying, land
appraisal, and stakeholder consultation. No prior study that assessed transmission options to
connect hydropower plants to Fort McMurray has been found in the public domain. Therefore,
the ROW of a given transmission line is selected by using the following criteria.




First, a 50 km wide buffer around the straight line connecting the sending and receiving
ends is selected as the study area
The straight line connecting the sending and receiving ends is selected as the initial ROW
Within the study area, where possible, obstacles such as large water bodies and protected
areas such as National Parks are avoided
If a transmission corridor is available within the study area, the ROW is adjusted to follow
existing lines
Transmission ROW formulation was done by utilizing a geographic information system (GIS). The
QGIS8 software tool and publicly available GIS data obtained from Natural Resources Canada
(Natural Resources Canada, 2014, 2015) is used for this task.
ROW width of a single circuit 500 kV HVAC and that of a ±500 kV HVDC bipole is about 60m.
Those ROW widths are used for ROW land cost calculation. However, environmental, economic,
and social impacts of the transmission line extend beyond its ROW. For example, visual impacts
may be apparent as far as 500m from the center of the ROW; fragmentation of forested areas by
transmission lines would affect wildlife movements; transmission towers and lines on agricultural
land would impede the ability to utilize farming machinery, reducing productivity.
Therefore, a 1 km wide corridor is used for ecological and social impact estimations. Impacts
within the full study area (i.e., 50 km wide buffer that encompasses the ROW) are also estimated
and presented in Appendix A.
Levelized Cost of Delivered Electricity and GHG Emissions
Abatement Cost
Generation and transmission options described in the preceding sections are combined to
formulate six hydropower generation and transmission options.
In addition to the six hydropower options, this study also assesses a baseline or reference power
generation option. The reference option assumes that electricity demand will be satisfied by
using natural gas-fired cogeneration plants. This assumption is consistent with current
operations and announcements made by investors (Murillo, 2015; OSDG, 2013). Furthermore,
cogeneration is an efficient and economical option to satisfy both thermal and electricity
8
QGIS is an open source GIS tool. It is available from: www.qgis.org
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demands of oil sands operations at a high reliability (Doluweera et al., 2011). Since cogeneration
units are onsite, as far as the electricity consumed by a given oil sands operation is concerned,
no transmission costs or losses are incurred. The cogeneration reference plant in this study is
assumed to be a gas turbine-based cogeneration plant with duct firing ability in the heat recovery
steam generator to have higher control over thermal energy production. Since a cogeneration
plant produces both electricity and thermal energy, costs and emissions that are chargeable for
the electricity portion is considered for this analysis (AESO, 2012; Doluweera et al., 2011; Suncor
Energy & Jacobs Consultancy, 2012).
In this study, the identified electricity generation and delivery options are screened using a
levelized cost of electricity (LCOE) metric (Kammen & Pacca, 2004; NETL, 2008). LCOE, measured
in $/MWh, is a metric that represents the cost of constructing and operating an electric power
generating plant. It is a standard metric used for screening and comparing different power
generating options. LCOE is calculated using the information available at the point of decision
making, based on discounted project cash flow analysis (Kammen & Pacca, 2004; Rubin, 2012).
In this study we calculate the LCOE of delivered electricity as follows, taking into account both
the generation and transmission systems.
𝐿𝐶𝑂𝐸 =
(𝐶𝐶𝑔 ∙ 𝑐𝑐𝑓𝑔 + 𝐹𝐶𝑔 + 𝑉𝐶𝑔 + 𝐶𝐶𝑡 ∙ 𝑐𝑐𝑓𝑡 + 𝐹𝐶𝑡 + 𝑉𝐶𝑡 )
𝐸𝑔𝑒𝑛 + 𝐸𝑙𝑜𝑠𝑠
Where,
CCx = capital cost ($)
FCx = annual fixed operating and maintenance cost ($/year)
VCx = annual variable cost ($/year)
Egen = annual electricity generation (MWh/year)
Egen = Rated capacity of the power plant (MW) · 8760 (h) · capacity factor (%)
Eloss = transmission losses (MWh/year)
x = g for generating plant
x = t for transmission system
ccfx = annual capital charge factor (/year) and it is calculated using the following equation
𝑟(1 + 𝑟)𝑁
𝑐𝑐𝑓 =
(1 + 𝑟)𝑁 − 1
Where, r = discount rate; N = Project economic life.
Table 2.1: Assumptions Made in Calculating Capital Charge Factor
Option
Cogeneration plant
Hydropower plant
Transmission lines
Discount rate
(base value)
10%
6%
6%
Discount Rate
(range used for
sensitivity analysis)
8% - 12%
4% - 8%
4% - 8%
Project
Economic Life
(years)
30
60
60
ccf
(base value)
10.6%/year
6.19%/year
6.19%/year
Source: CERI
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Real discount rates (i.e., discount rate adjusted for inflation) are used for this analysis.
Furthermore, different discount rates are used for the cogeneration reference case (baseline
option), hydropower options, and transmission system. It should be noted that in contrast to the
cogeneration reference case, hydropower plants and transmission systems are very long-lived
assets (60-100 years for a hydropower plant and 40-60 years for a transmission system).
Discount rates for this analysis are selected by taking into account the operational lives of
respective assets and weighted average cost of capital (WACC) of relevant investors (AltaLink,
2012; BC Hydro, 2013a; Manitoba Hydro, 2013). For high capital-intensive projects such as
hydropower plants and transmission lines, ccf (specifically the discount rate r) has a high impact
on LCOE. Therefore, a sensitivity analysis is conducted against the discount rate. Discount rate
and project life assumptions used for this analysis are given in Table 2.1.
Cost of GHG emissions abatement (henceforth referred to as cost of avoided carbon dioxide, or
CACO2) of a given hydropower generation and transmission option against the cogeneration
baseline option is calculated as follows:
𝐶𝐴𝐶𝑂2 =
𝐿𝐶𝑂𝐸ℎ𝑝 𝑜𝑝𝑡𝑖𝑜𝑛 − 𝐿𝐶𝑂𝐸𝑏𝑎𝑠𝑒𝑙𝑖𝑛𝑒 𝑜𝑝𝑡𝑖𝑜𝑛
𝐸𝑀𝐼𝑏𝑎𝑠𝑒𝑙𝑖𝑛𝑒 𝑜𝑝𝑡𝑖𝑜𝑛 − 𝐸𝑀𝐼ℎ𝑝 𝑜𝑝𝑡𝑖𝑜𝑛
Where,
LCOEx = Levelized cost of delivered electricity (in $/MWh) of the hydropower option (x=hp
option) / baseline option (x=baseline option)
EMIx = GHG emissions intensity (in tCO2e/MWh)
CACO2 is a standard metric used for screening GHG emissions abatement options. It calculates
the cost of avoiding a tonne of atmospheric CO2 emissions while providing a unit of useful energy
(i.e., MWh of electricity) (Rubin, 2012). It should be noted that CACO2 is measured against a
reference option, which in general, has a higher GHG emissions intensity and lower LCOE. CACO2
can also be interpreted as the price of CO2 emissions that would make the LCOE of the low GHG
emissive option the same as that of the reference plant.
Uncertainty Assessment
Parameters such as capital costs, fuel prices, and capacity factors that are used for point
estimates of LCOE and CACO2 have considerable degrees of uncertainty associated with them.
For example, the hydropower options assessed in this study are in different planning stages and
the accuracy of the capital cost estimates, as indicated by the project developers, are in the range
of -15 percent to +30 percent of the reported value; capacity factors depend on river flow levels
and precipitation patterns.
In order to ensure the robustness of the information available for decision makers with respect
to large infrastructure projects, it is important that uncertainty associated with the results be
explicitly assessed. In order to assess uncertainty associated with the LCOE and CAOC2 of the
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electricity generation and delivery options explored in this study, a Monte Carlo simulation (MCS)
is developed.
To carry out a MCS, the probability distributions of the main parameters are identified. Each
parameter is then sampled from their probability distributions. These samples are then used to
calculate the relevant metrics (in this study LCOE and CACO2) and important attributes by which
those metrics are identified by utilizing statistical techniques (e.g., mean, variance and
percentiles of the metrics).
In this study, the impact of the following parameters are assessed by developing a MCS with
100,000 samples. Each parameter is assumed to be uniformly distributed.




Capital costs of generation and transmission assets
Capacity factors
Natural gas price
Electricity price at the Mid-Columbia (Mid-C) electricity hub
Decision making under uncertainty is sometimes based on point source information instead of
uncertainty ranges. For clarity, this analysis focuses on point source estimates; however,
Appendix C contains a detailed probability assessment of the different options showing how the
selection order may change based on the MCS.
Estimation of Environmental and Social Impacts
Large energy infrastructure projects such as development of hydropower plants and long
distance transmission lines inevitably lead to undesirable social and environmental impacts.
Stakeholder perception on those impacts can potentially delay or halt permitting, siting, and
construction of energy infrastructure. Stakeholder opposition of hydropower and transmission
development, particularly against three new hydropower plants assessed in this study, was
observed across Canada (Anderson, 2013; CBC News, 2010; Henton, 2013; Hunter, 2015; Larkins,
2015). Therefore, it is important that these impacts are quantified and stakeholders are
consulted early in the screening phase of a project.
Social and environmental impacts are estimated by identifying a set of relevant project attributes
and quantifying them (Keeney & Gregory, 2005). For example, when quantifying the impact on
sensitive ecosystems by an electricity transmission line project, one attribute that can be utilized
is the ecosystem area (say, in hectares) within the transmission ROW. Social and environmental
impacts quantified in this study and the associated attributes are described in the following
sections.
Quantification is not monetization. Monetization can be situation-specific and based on the
judgement of the stakeholder. Physical quantification provides greater transparency and allows
decision makers to assess their own value of the environmental and social impacts.
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The area considered for impact estimates includes a 1 km wide buffer that encloses the selected
transmission line corridor and a circular buffer with a 5 km radius that encloses the hydropower
plant. Combination of these two buffers are henceforth referred to as the direct impact area.
All impacts are calculated using publicly available GIS data.
Residential and Property Value Impacts
Residential and property value impacts encompass a multitude of public concerns against energy
infrastructure. These include, but are not limited to visual impacts, perceived health impacts due
to exposure to electromagnetic fields (EMF) caused by the lines, impacts on future development,
and potential reduction of property value due to a transmission line being within close proximity
of respective properties. Furthermore, development of hydropower plants could potentially lead
to involuntary displacement of a population due to reservoir flooding. This study estimates the
population and number of dwellings in the direct impact area as two high-level metrics of
residential and property value impacts. Population and number of dwellings are estimated by
using 2011 Canada Census data (Statistics Canada, 2012) as follows:
𝑃𝑜𝑝𝑢𝑙𝑎𝑡𝑖𝑜𝑛 =
∑
(
𝑎𝑙𝑙 𝑐𝑒𝑛𝑠𝑢𝑠
𝑠𝑢𝑏𝑑𝑖𝑣𝑖𝑠𝑖𝑜𝑛
𝑃𝑜𝑝𝑢𝑙𝑎𝑡𝑖𝑜𝑛 𝑑𝑒𝑛𝑠𝑖𝑡𝑦
𝑐𝑒𝑛𝑠𝑢𝑠 𝑠𝑢𝑏𝑑𝑖𝑣𝑖𝑠𝑖𝑜𝑛 𝑎𝑟𝑒𝑎
)×(
)
𝑤𝑖𝑡ℎ𝑖𝑛 𝑡ℎ𝑒 𝑑𝑖𝑟𝑒𝑐𝑐𝑡 𝑖𝑚𝑝𝑎𝑐𝑡 𝑎𝑟𝑒𝑎
𝑜𝑓 𝑎 𝑐𝑒𝑛𝑠𝑢𝑠 𝑠𝑢𝑏𝑑𝑖𝑣𝑖𝑠𝑖𝑜𝑛
𝑁𝑜. 𝑜𝑓 𝑑𝑤𝑒𝑙𝑙𝑖𝑛𝑔𝑠
=
∑
𝑎𝑙𝑙 𝑐𝑒𝑛𝑠𝑢𝑠
𝑠𝑢𝑏𝑑𝑖𝑣𝑖𝑠𝑖𝑜𝑛
𝐷𝑤𝑒𝑙𝑙𝑖𝑛𝑔𝑠 𝑑𝑒𝑛𝑠𝑖𝑡𝑦
𝑐𝑒𝑛𝑠𝑢𝑠 𝑠𝑢𝑏𝑑𝑖𝑣𝑖𝑠𝑖𝑜𝑛 𝑎𝑟𝑒𝑎
(
)×(
)
𝑤𝑖𝑡ℎ𝑖𝑛 𝑡ℎ𝑒 𝑑𝑖𝑟𝑒𝑐𝑐𝑡 𝑖𝑚𝑝𝑎𝑐𝑡 𝑎𝑟𝑒𝑎
𝑜𝑓 𝑎 𝑐𝑒𝑛𝑠𝑢𝑠 𝑠𝑢𝑏𝑑𝑖𝑣𝑖𝑠𝑖𝑜𝑛
Agricultural Impacts
Agricultural impacts stem from loss of agricultural land due to reservoir flooding and siting
transmission lines on agricultural lands. Areas of agricultural land within the direct impact area
are estimated by using land cover data set obtained from Natural Resources Canada (Natural
Resources Canada, 2014).
Impacts on Indigenous Populations
Development of energy infrastructure in areas inhabited by Indigenous people affects their lives
in multiple ways. Direct impacts stem from developing hydropower plants and transmission lines
on Indigenous lands. Other adverse impacts of hydropower and transmission line development
can potentially impede fishing, hunting, and trapping rights as well as cultural heritage resources
of the affected population. In this study, as a proxy measure of impacts on Indigenous
populations, reserve areas within the direct impact area is estimated by utilizing GIS tools. No
other designated Indigenous land (e.g., Metis settlements) is observed within the study area.
Indigenous lands geographic datasets were obtained from Natural Resources Canada (2015).
Both number (partially or fully enclosed by the direct impact area) and First Nations reserves are
estimated.
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Environmental Impacts
Altering the natural habitat for hydropower and transmission developments will directly and
indirectly impact the biodiversity of the habitat and ecosystem services attributable to the area.
These ecosystem services include water regulation, soil formation and erosion control, food
production, provision of raw material, climate regulation and recreational services. Quantifying
these impacts is important at the screening stage of options to satisfy energy demands to ensure
responsible resource developments and to identify the necessary regulatory requirements that
need to be complied with.
The main environmental impacts associated with options assessed in this study include potential
impacts on environmentally sensitive areas (e.g., wetlands, national parks, etc.), methylmercury
formation due to reservoir flooding, avian mortality due to collision with power lines, soil erosion,
and wildlife habitat defragmentation due to new linear disturbances. This study estimated two
metrics as proxies of environmental impacts. One metric is the area of protected areas (national
parks, provincial parks, migratory bird sanctuaries, etc.) within the direct impact area. The other
metric is area of water bodies (rivers, lakes, and wetlands) within the direct impact area. GIS
data from the CanVec+ catalogue is primarily used to estimate environmental impacts (Natural
Resources Canada, 2014).
It is plausible that environmentally significant land may lie outside the boundaries of protected
areas (for example, boreal forest, grasslands, private land). Therefore, the full land cover of the
direct impact area is estimated and classified using GIS tools.
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Chapter 3
Results
Hydropower Generation and Transmission Options
Specific details of the six hydropower generation and transmission options assessed in this report
are described in this section. Key details of these six options are summarized in Table 3.1.
Table 3.1: Summary of Hydropower Generation and Transmission Options
Option
Site C-DC
Site C-AC
BC
Intertiei
Slave
River-DC
Slave
River-AC
Manitoba
DC
Hydropower Generation Plant
Site and River
Province
Rated
System
Capacity
(MW)
Site C on the
British
1100
Peace Rive
Columbia
Site C on the
British
1100
Peace Rive
Columbia
British
Increase
Columbia
by 500
Alternative 4
Alberta
1100
site on the
Slave River
Alternative 4
Alberta
1100
site on the
Slave River
Conawapa site
Manitoba
1485
on the Nelson
River
Transmission System
Technology
No. of
Length
Lines
(km/line)
±500 kV HVDC
bipole
Single circuit
500kV HVAC
Single circuit
500kV HVAC
±500 kV HVDC
bipole
1
600
2
600
1
400
Single circuit
500kV HVAC
2
400
±500 kV HVDC
bipole
1
1100
i
The BC Intertie option assumes a case where the existing BC-AB intertie is reinforced to import higher amounts of
hydropower purchased from the BC Hydro system. Therefore, no new hydropower plants or new transmission lines
are attributed to this option. The capital cost of this option is assumed to be the reinforcement cost of the BC-AB
transmission intertie.
Source: CERI
Alberta-BC Options
Two hydropower generation and transmission options assume that electricity produced by the
Site C dam and associated hydropower plant is transported to Alberta via a new transmission
line. The Site C dam is being constructed approximately 7 km southwest of the town of Fort St.
John. The Site C-DC option assumes that a single ±500 kV HVDC bipole transmission system is
used to transmit electricity from the Site C hydropower plant to Fort McMurray, AB.
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The Site C-AC option assumes that two 500 kV single circuit HVAC transmission systems are used
to move electricity from the Site C plant to Fort McMurray, AB. As discussed in Chapter 2, in the
case of HVAC options, two transmission circuits are used to ensure system reliability. Figure 3.1
depicts the power plant locations and the transmission corridor. As can be seen in Figure 3.1,
the transmission corridor would span across a mixture of agricultural land, populated areas,
forests, and protected areas.
Figure 3.1: Alberta-BC Hydropower Generation and Transmission Options
(Site C-DC and Site C-AC Options)
A third BC-Alberta option, the BC Intertie, assumes reinforcement of the existing AB-BC intertie
(a 500 kV HVAC line between Cranbrook, BC and Langdon, AB) to utilize the full 1,200 MW
capacity of the line and deliver hydroelectric power purchased from the BC electric power
system. Currently only about 50 percent of the existing BC-AB intertie is being utilized.
Alberta-Manitoba Option
The Manitoba DC option assumes that the proposed Conawapa hydropower plant on the Nelson
River in Manitoba is developed and a single ±500 kV HVDC bipole transmission system is used to
transmit electricity to Fort McMurray, AB. If developed, the Conawapa plant would be the eighth
hydropower plant on the Nelson River. The Nelson River hydroelectric system currently has six
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plants in operation and another one under construction. Figure 3.2 depicts the location of the
hydropower plants and the transmission line corridor.
Figure 3.2: Alberta-Manitoba Hydropower Generation and Transmission Option
(Manitoba DC Option)
Alberta Slave River Options
The Slave River-DC and Slave River-AC options assume that a hydropower plant would be
developed on the Alberta Slave River. Based on previous proposals, the most likely location of
the plant would be a site called Alternative 4 Site, just south of the border between Alberta and
the Northwest Territories. Figure 3.3 depicts the most likely location of the power plant and
transmission lines that would connect it to Fort McMurray.
The Slave River-DC option assumes that a single ±500 kV HVDC bipole transmission system is used
to transmit electricity from a hydropower plant at the Alternative 4 Site to Fort McMurray, AB.
The Slave River-AC option assumes that two 500 kV single circuit HVAC transmission systems are
used to transmit power to Fort McMurray from the same hydropower plant.
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Figure 3.3: Alberta Slave River Hydropower Generation and Transmission Options
Levelized Cost of Electricity (LCOE) and Cost of Avoided CO2
The LCOE of the cogeneration reference case and six hydropower options are estimated using
the data listed in Table 3.2. CACO2 of the hydropower options are also estimated. Estimated
values of LCOE and CACO2 are presented in Table 3.2, Figure 3.4 (LCOE), and Figure 3.5 (CACO2).
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Table 3.2: LCOE and CACO2 Estimates (base case estimates)
Cogen
Reference
Case
Generation
Rated capacity (MW)
Capacity factor (%)
Annual power generation
(GWh/year)
Capital cost (million $)
Overnight cost
Contingency &
escalation
IDCii
Capital cost ($/kW)
Capital charge factor (%)
Fixed O&M cost (million
$/year)
Fuel cost ($/MWh)iii
GHG intensity
(kgCO2e/MWh)
LCOE (Generation only)
Transmission
Trans. circuit length (km)
Capital cost (million $)iv
Capital charge factor (%)
O&M cost (million
$/year)
Transmission losses
(GWh/year)
LCOE
CACO2 Cogen ref. option v
CACO2 AB Grid vi
CACO2 Coal vii
HVDC Options
Intertie
Option
BC
Intertiei
HVAC Options
Site
C-DC
Slave
River-DC
Manitoba
DC
Site C-AC
Slave
River-AC
1000
85
7446
1100
53
5100
1100
68
6552
1485
54
7000
1100
53
5100
1100
68
6552
2070
1448
435
8444
4830
1564
8800
4830
1835
9541
5610
1704
8444
4830
1564
8800
4830
1835
188
2071
10.61
14
1668
7677
6.19
16
1739
8003
6.19
17
1908
6425
6.19
16
1668
7677
6.19
16
1739
8003
6.19
17
26.0
325
5.5
11
3.8
5
1.8
5
5.5
11
3.8
5
42.5
11
57.4
111
89.4
88.4
111
89.4
42.5
0
0
6.34
0
600
1984
6.34
10
400
1789
6.34
9
1100
3141
6.34
16
1200
3079
6.34
15
800
2560
6.34
11
318
280
6.34
93
0
122
127
253
292
250
196
57
141
266
107
72
110
165
62
33
124
207
82
50
162
332
137
98
121
198
77
47
81
75
21
-3
500
75
3285
Notes: All costs are in 2014 Canadian dollars. LCOE excludes taxes charged by respective jurisdictions
i
Power generation capital and operating costs are irrelevant for the BC Intertie option as no dedicated hydropower
plant is assumed. Electricity imports are assumed to be purchased at the average peak electricity price at the MidColumbia (Mid C) gate.
ii
IDC = Interest accumulated during construction (also known as capitalized interest)
iii
Fuel cost of the cogeneration reference case is calculated assuming a natural gas price of $4/GJ (hhv) and heating
value of 6.5 GJ/MWh; fuel cost of hydropower options is the water rental fees; non-fuel variable O&M are
assumed to be negligible
iv
Interest accumulated during construction and contingencies are included in the capital cost
v
CACO2 is estimated against the cogeneration reference case
vi
CACO2 is estimated against the Alberta grid average with an average price of $66/MWh and average grid
emissions intensity of 710 KgCO2/MWh for the 2010-2014 period. These parameters are estimated using data
published by AESO (2015a)
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vii
CACO2 is estimated against coal-fired generation displacement reference option with an average cost of
generation of $82/MWh and emissions intensity of 820 kgCO2/MWh.
Data sources:
Generation overnight capital cost, capacity factors:
Site C-DC, Site C-AC: BC Hydro (2013a); Manitoba DC: Manitoba Hydro (2013); cogeneration: AESO (2012)
Slave River-DC/Slave River-AC overnight capital cost is assumed the same as Site C.
Slave River-DC/Slave River-AC capacity factor is estimated using flow rate data from Environment Canada (2015a)
and SRSC (1980)
New transmission costs and losses: Black & Veatch (2014)
AB – BC intertie reinforcement costs: AESO (2015b)
The abatement costs of CO2 are sensitive to the reference case used. Costs are lowest when
compared to higher emitting sources such as coal generation and lower compared to the more
efficient generation of electricity through natural gas cogeneration.
Figure 3.4: Levelized Cost of Electricity (LCOE) Delivered to Oil Sands Operations in Alberta
under Different Generation and Transmission Options
Source: CERI
LCOE represents the average cost of constructing and operating an electric power generation or
transmission system. The reference option (base case) assumes that natural gas-fired
cogeneration units satisfy electricity demands. All hydropower options have higher LCOE than
the cogeneration reference option when both generation and transmission costs are taken into
account.
The BC Intertie option, which assumes hydropower is bought from the BC Hydro system and
delivered to Alberta using the existing intertie, is the hydropower option with the lowest LCOE.
Generation costs of Slave River hydropower options (Slave River-DC and Slave River-AC) and the
Conawapa hydropower option (Manitoba DC) appear to be the same, although the greater
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transmission distance makes the LCOE of Manitoba DC higher than the Slave River options. When
both HVDC and HVAC transmission options are considered for a given hydropower plant, the
HVDC option leads to lower transmission costs due to shorter effective circuit length (HVAC
options have two independent transmission circuits) and lower losses.
Figure 3.5: Cost of Avoided GHG Emissions (CACO2)
Source: CERI
Among the options where new hydropower plants are developed, the Alberta Slave River options
(Slave River-DC/Slave River-AC) have the lowest LCOE and CACO2. Both generation and
transmission costs of the Slave River options are lower than other new hydropower options. This
is mainly due to high capacity factors that lowered the generation cost and lowered transmission
distance. For the two hydropower options where two transmission options are assessed, HVDC
options have lower costs than HVAC options. This is because two HVAC lines are required to
ensure sufficient transmission capacity and system reliability (see Figure 3.6).
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Canadian Energy Research Institute
Figure 3.6: Capital Cost Contribution of Different Transmission System Components
Source: Cost data from Black & Veatch (2014); figure by CERI
In this assessment, transmission line investment costs are estimated by utilizing a model
developed by Black & Veatch (2014) for the western region of the North American power system.
In terms of investment cost per transmission distance basis, the estimated values that are
depicted in Figure 3.6 are comparable to recently completed or planned major transmission line
projects in Western Canada. For example, the investment cost of HVDC lines of Site C-DC, Slave
River-DC, and Manitoba DC options are in the order of $3.3-$4.4 million/km. Capital costs of two
HVDC monopole lines are in the order of $4-$4.4 million/km. The capital cost of the Bipole III
project, which would build a 1,400 km HVDC bipole line in Manitoba, is estimated to be $3.3
million/km.
Figure 3.7 indicates the amount of electricity that can be supplied by different hydropower
options along with the respective LCOE values. It also indicates the equivalent in-situ bitumen
extraction amount, of which electricity demand can be satisfied by power delivered under a given
option. Site C-AC and Slave River-AC options are not depicted in this figure as they connect the
same hydropower plant as Site C-DC and Slave River-DC. Similarly, Figure 3.8 depicts the amount
of GHG emissions that can be avoided by the different options.
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Figure 3.7: Electricity Supply Curve
Source: CERI
Figure 3.7 depicts the amount of electricity that can potentially be delivered to Fort McMurray
under different hydropower options along with respective LCOE estimates. Equivalent bitumen
extraction estimates assume in-situ bitumen extraction. As can be seen from the figure, although
the BC Intertie has the lowest LCOE, the estimated amount of delivered energy is less than half
of other hydropower options.
Figure 3.8 depicts the emissions abatement potential of hydropower options along with their
CACO2 estimates. CACO2 estimates of new hydropower options are double or more compared
to the BC Intertie option.
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Figure 3.8: GHG Emissions Abatement Supply Curve
Source: CERI
Estimates of CACO2 are sensitive to the reference case electricity supply that is to be displaced
by hydropower options. When the cogeneration reference is considered, the estimated CACO 2
values are relatively high for most hydropower options due to lower average costs of
cogenerated electricity and lower emissions intensity.
Adding onsite cogeneration to an oil sands operation requires additional investments and
increases operational complexity. Therefore, it is also plausible that the oil sands operators may
choose to purchase electricity from the Alberta electricity market, instead of onsite generation.
Therefore, CACO2 is also estimated against a case where Alberta average grid electricity is
displaced by hydropower. The average price of grid electricity and average emissions intensity
are assumed to be $66/MWh and 710 kg CO2eq/MWh, respectively. Those values represent the
average conditions in the Alberta electricity market over the period 2010-2014.1 The reference
case could also be the coal-fired generation that currently accounts for the largest share of
electricity generation in Alberta. Coal-fired generation is being phased out in Alberta but still
forms a plausible reference case to compare GHG abatement costs of displacing high emissive
electricity. For the coal-fired electricity reference case, the reference plant is assumed to be the
Keephills 3 (Capital Power, 2011). This is the last coal power plant that was added to the Alberta
generation fleet and the unit that is most likely to remain in the fleet over the next few decades
in the absence of GHG emissions constraints (AESO, 2012). For this reference case, a LCOE of
1
Calculated using the data published in (AESO, 2014a)
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$83/MWh and a GHG emissions intensity of 820 kg CO2eq/MWh are assumed.2 CACO2 estimates
based on these two alternative reference options are presented in Table 3.2.
As can be seen from Table 3.2, the CACO2 values correspond to the Alberta grid replacement
reference case and are 60-70 percent lower than those of the cogeneration reference case. When
replacing new coal-fired generation with the BC Intertie, the abatement cost is negative because
the assumed cost of BC Intertie electricity is less than the reference coal power plant. The relative
ranking of hydropower options in terms of CACO2 remains unchanged with the choice of
reference option.
Sensitivity Analysis against Discount Rate
Sensitivity analysis against the discount rate used for the LCOE calculation was carried out and
the resulting supply curves are depicted in Figures 3.9 and 3.10. The analysis used discount rates
of Base = 6 percent; Low = 4 percent; High = 8 percent. As can be seen from those results, the
relative placements of different options did not change with the discount rate. The impact of a
discount rate on LCOE and CACO2 is significant for options with high capital expenditure.3
Although not depicted here, the impact of discount rate variation on LCOE of the cogeneration
reference option is relatively low.
Impacts of variations in other important parameters (e.g., capital costs, capacity factors, etc.) are
examined in Appendix C, through a probabilistic uncertainty assessment based on a Monte Carlo
simulation. This assessment provides insights into the robustness of the results and how the
selection order may change with variations in different parameters.
2
Calculated using the information available at: Capital Power, “Keephills 3 Power Plant Begins Commercial
Operation,” 2011, http://www.capitalpower.com/MediaRoom/newsreleases/2011-newsreleases/Pages/090111.aspx. A discount rate of 10% over 30 years is assumed.
3
1 percent change in discount rate leads to 13-14 percent change in LCOE and 23-24 percent change in CACO2
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Figure 3.9: Electricity Supply Curve Sensitivity Analysis against Discount Rate
Source: CERI
Figure 3.10: GHG Emissions Abatement Supply Curve Sensitivity Analysis against
Discount Rate
Source: CERI
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Economic Assessment of Electrical Extraction Technologies
If a low/zero emission supply of electricity such as hydroelectric power is available, deeper GHG
emissions reductions can be achieved in the oil sands sector through adaptation of electrical
extraction technologies. As such, this section provides estimates of CO2 abatement costs of using
six hydropower options assessed in the report for electrical extraction of bitumen. The main
challenge in estimating the CO2 abatement cost of electrical extraction technologies is that those
technologies are still in demonstration or experimental stage and data on their costs, energy
intensities, and other relevant performance parameters (e.g., full list of energy and material
inputs) are not available in the public domain. Therefore, this assessment provides preliminary
estimates of abatement costs and technology costs in the form of a scenario analysis.
In contrast to current in-situ extraction methods, electrical extraction techniques such as
Effective Solvent Extraction Incorporating Electromagnetic Heating (ESEIEH) and Electro-Thermal
Dynamic Stripping Process (E-T DSP™) employ alternative extraction techniques where all energy
inputs are replaced with electricity. Therefore, the abatement cost is the cost of CO2 emissions
that would make the average production cost4 per barrel of an electrical extraction technology
the same as that of a reference bitumen extraction process.
For this assessment, the reference (or the baseline) extraction process is:





SAGD bitumen extraction facility
production capacity of 30,000 barrels per day
thermal demand is 1.3 GJ/bbl, which represents the sector wide average SAGD thermal
energy demand (Nduagu & Gates, 2015)
electricity demand is 16.5 kWh/bbl (Murillo, 2015)
natural gas-fired 85 MWe cogeneration system and a natural gas-fired supplementary
boiler
Excess electricity produced by the cogeneration system is assumed to be exported to the Alberta
grid and costs and emissions associated with exported electricity are excluded from the facility’s
accounts. Full details of the reference SAGD facility along with its energy costs and emissions are
presented in Appendix B. According to the estimates presented in Appendix B, the energy cost
of the reference facility is $5.9/bbl5 and associated GHG emissions are 67 kgCO2e/bbl.
In the 2014 long term outlook, AESO (2014a) assumes that the electricity demand for electricity
based extraction technologies to be 180 kWh/bbl. A recent assessment by CERI assumes the
same energy intensity. An estimate based on process simulations reports the electricity demand
of ESEIEH technology to be 44 kWh/bbl (= 0.16 GJ/bbl or approximately 15 percent of SAGD
energy demand) (Patterson, 2015). Due to the data limitations, this assessment takes into
account four different energy intensities, where the electricity energy demand for bitumen
4
5
Average production cost takes into account both capital and operating costs
Natural gas price is assumed to be $4/GJ
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extraction is assumed to be 15 percent, 25 percent, 50 percent and 100 percent of the total
energy demand of the reference SAGD facility (= 1.36GJ/bbl or 378 kWh/bbl).
For each combination of the four electricity demand cases and six hydropower generation and
transmission options (a total of 24 scenarios), the bitumen production potential, electrical energy
cost, avoided GHG emissions, and minimum abatement cost (i.e., CACO2) are calculated. For this
assessment, it is assumed that geological costs (site preparation, drilling, etc.) are the same for
the reference SAGD facility and the electrical extraction facility.
Minimum CACO2 of a given scenario is the price of CO2 that would make its energy cost the same
as the average energy cost of conventional SAGD when the non-fuel energy cost6 is set to be
zero. Impacts of taxes and royalties are excluded from this assessment. Impacts of emissions
associated with non-energy material inputs (e.g., solvents for ESEIEH process) are also excluded.
Table 3.3: Minimum CACO2 and Other Metrics of Electrical Extraction Scenarios
Production Potential
(1,000 bbl/day)
Site C-DC
Slave RiverDC
Manitoba DC
Site C-AC
Slave RiverAC
BC Intertie
Electrical Energy Cost
($/bbl)
Minimum CACO2i
($/tCO2e)
Avoided Emissions
(million tCO2e/year)
15%
25%
50%
100%
15%
25%
50%
100%
15%
25%
50%
100%
15%
25%
50%
100%
247
148
74
37
8
13
27
53
6.0
3.6
1.8
0.9
31
112
319
752
317
190
95
48
6
10
21
42
7.7
4.6
2.3
1.1
5
67
225
547
339
247
203
148
102
74
51
37
7
9
12
15
23
31
47
61
8.2
6.0
4.9
3.6
2.4
1.8
1.2
0.8
17
49
87
142
265
380
629
880
317
190
95
48
7
11
23
46
7.7
4.6
2.3
1.1
14
83
257
612
159
95
48
24
5
8
15
31
3.8
2.3
1.1
0.5
-
26
145
393
Source: CERI
The four metrics estimated for each scenario are presented in Table 3.3. As can be seen,
compared to the reference SAGD facility, higher amounts of avoided emissions could be achieved
by deploying electrical extraction techniques (95-99 percent reduction). However, as more
electricity is needed for bitumen extraction, the bitumen production potential of a given
hydropower generation and transmission option is relatively lower (24,000-339,000 bbl/day)
resulting in a higher energy cost per barrel ($5-61/bbl).7 In the case of the BC Intertie option,
when the non-energy cost is set to zero, the electrical extraction option is preferred to
conventional SAGD even without a price on CO2. The bitumen extraction potential of all scenarios
that involve the BC Intertie electricity supply option are the lowest.
Minimum CACO2 estimates of electrical extraction scenarios presented in Table 3.3 assume the
non-fuel energy costs are zero. However, it is inevitable that the extraction process would incur
additional costs. Therefore, minimum CACO2 can be interpreted as the lower limit of the CACO2
6
Non-fuel energy costs include all fixed and operating costs associated with implementing the extraction process
such as all additional equipment, non-energy inputs (e.g., solvents used for ESEIEH process), etc.
7
Note that this only includes the cost of electricity
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that would make electrical extraction preferred to conventional SAGD.8 In order to gain insights
into the magnitude of the non-fuel energy costs, a sensitivity analysis against the CACO2 is
conducted in Figure 3.11.
Figure 3.11: Sensitivity Analysis of CACO2 for Electrical Extraction Technologies
Source: CERI
Figure 3.11 provides useful information to assist investment and research and development
(R&D) decisions pertaining to electrical extraction technologies. At the assumed natural gas price
and hydropower development cost, the non-fuel extraction cost represents the upper limit of
the metric that could be afforded at a given CACO2 value.
For a given electricity intensity (e.g., 15 percent, 25 percent, etc.) the area below the
corresponding line represents the values of CACO2 and non-fuel extraction costs that would make
the electrical extraction method preferred to SAGD extraction. None of the scenarios with
electricity intensity of 100 percent appear in this figure as their minimum CACO2 is more than
$300/tCO2e.
Social and Environmental Impacts of Hydropower Options
The social and environmental impacts are estimated by quantifying the land cover within the
direct impact area.9 Only the impacts pertaining to new hydropower options are quantified,
8
At the assumed natural gas price and hydropower development costs
Direct impact area is defined as the area formed by a combination of a 1 km wide buffer that encloses the
selected transmission line corridor and a circular buffer with a 10 km radius that encloses the hydropower plant)
9
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excluding the cogeneration reference case. It is assumed that cogeneration units would be sited
within an oil sands facility, resulting in no additional impacts attributable to electricity. The main
exception is GHG emissions, which have been quantified for all options in CACO2 calculations.
Similarly, the BC Intertie option that utilizes existing energy infrastructure would not have
additional impacts. HVDC and HVAC transmission options are not distinguished, as the 1 km wide
buffer is sufficient to site either of the transmission systems. Consequently, the five new
hydropower options are re-categorized as follows for impact calculations:



AB Slave River: Corresponds to Slave River-DC or Slave River-AC
AB-BC: Corresponds to Site C-DC or Site C-AC
AB-MB: Corresponds to Manitoba DC
Land cover within the respective direct impact areas is quantified in Figure 3.12. Land categories
and quantification is carried out by utilizing the CanVec+ dataset (Natural Resources Canada,
2014). It can be seen that the direct impact areas mainly encompass boreal forest, wetlands, and
water bodies (i.e., rivers and lakes). In the case of the AB Slave River options, those three land
categories cover 96 percent of the direct impact area. For the AB-BC and AB-MB option the
coverage of those three land categories are 66 percent and 76 percent, respectively.
Figure 3.12: Land Cover within the Direct Impact Area
Source: CERI
In Figure 3.13, the population and number of dwellings within the direct impact area are
quantified as a proxy metric of the residential and property value impacts. According to the
results, the vast majority of residential and property value impacts are concentrated in Alberta.
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New hydropower options from BC (Site C-DC and Site C-AC) appears to have the highest
residential and property value impacts and they are mainly concentrated to areas surrounding
the towns of Fort St. John, BC and Peace River, AB.
Figure 3.13: Population and Number of Dwellings in the Direct Impact Area
Source: CERI
One notable caveat of this study is that the land use impact assessment may not fully capture the
impacts of widening the Peace River by Site C dam construction (Site C-DC and Site C-AC options).
Construction of the Site C dam would widen the Peace River by up to three times the current
levels and flood an approximate 83 km stretch along the river. Furthermore, under all options,
construction of hydropower plants and transmission lines would inevitably require building of
construction roads and camps. Impacts that would result from these temporary structures are
not fully captured in this analysis. Assessment of those impacts require detailed, temporally
explicit land use assessments that are beyond the scope of this study.
Only the AB-BC options appear to cover notable areas of agricultural land. Based on the dataset
utilized (Natural Resources Canada, 2015), other new hydropower options do not have notable
agricultural impacts. Furthermore, the AB-BC options have the highest residential and property
value impacts. As can be seen from Figure 3.13, the population and number of dwellings in the
direct impact area of the AB-BC options are several times greater than the other options.10
It should be noted that these impacts could be minimized by careful route selection.
Furthermore, population and number of dwellings are estimated assuming uniform distribution
10
Based on 2011 Canadian census data
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within a given census sub-division. The actual distribution may be contrary to that assumption.
Nonetheless, the estimates depicted in Figure 3.13 provide general metrics of residential and
property value impacts.
Figure 3.14: Number and Area of First Nations Reserve Lands in the Direct Impact Area
Source: CERI
The number and area of First Nations reserves within the direct impact area are shown in Figure
3.14. According to these estimates, as far as direct impact areas are concerned, only the AB Slave
River and AB-MB options appear to have impacts on Indigenous populations. Furthermore,
Indigenous population impacts pertaining to the AB Slave River options occur only within Alberta
and those pertaining to the AB-MB option occur only within Manitoba. Impacts that would
potentially stem from factors such as water regulation by hydropower dams and construction
activities are not estimated in this study. Furthermore, quantification of impacts on Indigenous
peoples within the full study area (i.e., 50 km wide buffer enclosing the transmission ROW;
Figures 3.1-3.3) result in a much higher number of reserve areas affected (see Figures 3.1-3.3 and
Figure A.3 of Appendix A). When the full study area is taken into account, impacts on Indigenous
peoples extend to the AB-BC options as well as to five First Nations reserves in Saskatchewan.
The potential land impacts that would stem from widening the Peace River and some of the
tributaries by the construction of the Site C dam are not captured by this assessment. All of these
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factors emphasize the importance in consulting the relevant Indigenous communities in any
attempt to develop hydropower and transmission options assessed in this study.
Land cover within respective direct impact areas that are designated as protected areas at federal
or provincial levels due to their ecological value are depicted in Figure 3.15. Figure 3.15 also
depicts the area of water bodies within respective direct impact areas. These two proxy
indicators provide metrics of environmental impacts of the new hydropower options. The
amount of protected areas and water bodies impacted by new transmission options follow the
same order as the transmission ROW length (for example, AB-MB, with its longest ROW, impacts
the highest amount of protected areas).
Figure 3.15: Protected Areas and Water Bodies in the Direct Impact Area
Source: CERI
Protected areas impacted by new hydropower options are mostly provincial parks in respective
jurisdictions. The Alberta Slave River options, however, would impact federally protected Wood
Buffalo National Park (WBNP) and Richardson Lake Migratory Bird Sanctuary. WBNP, a UNESCO
World Heritage Site, is the second largest national park in the world. The park is the nesting
grounds of the last remaining wild flock of endangered Whooping Cranes in the world
(Environment Canada, 2015b).
All four North American migratory bird flyways cross the WBNP. Furthermore, development of
a hydropower plant and associated transmission infrastructure on the Slave River would
inevitably impact the Peace-Athabasca Delta (PAD), a globally important ecologically sensitive
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area. Due to its ecological importance, the PAD is protected under the Ramsar Convention (SRSC,
1980; Struzik, 2013).
The PAD is formed at the confluence of the Peace, Athabasca and Birch rivers at the western end
of Lake Athabasca. Since the landscape is relatively flat, many of its waterways can flow in two
directions depending on relative water levels, forming the delta (PADEMP, 2015). It is one of the
world’s largest freshwater deltas and has a profound impact on flora and fauna – which includes
214 species of birds, 42 species of mammals, and 20 fish species – as well as the traditional land
use practices of the surrounding Indigenous peoples communities.
The delta contains some of the largest undisturbed grass and sedge meadows in North America
(PADEMP, 2015). Ecosystem health of the PAD is directly linked to the hydrology of the northward
flows of the Peace and Slave rivers. Consequently, water level regulations by a potential
hydropower plant would inevitably impact the PAD. Moreover, construction activities11 may
disturb wildlife movement and increase the risk of spreading invasive species.
A hydropower plant development on the Slave River would impact a waterway that has not yet
been impounded. In contrast, Site C and Conawapa would be developed on rivers that have
already been impounded by existing hydroelectric dams.12 Due to these factors, of all the new
hydropower options assessed in this study, the Slave River options likely have the highest amount
of environmental impacts.
In this study, the extent of protected areas impacted by new hydropower options is estimated as
a proxy measure of environmental impacts. However, ecological impacts of hydropower and
transmission developments would extend well beyond the protected areas. As evident on Figure
3.12, a greater proportion of land within the respective direct impact areas contains Canada’s
boreal forest and wetlands intermingled with it.
Canada’s boreal forest region is a complex ecosystem that supports thousands of species of flora
and fauna and contains a significant proportion of the world’s surface freshwater (Pew
Environment Group, 2012). Only a fraction of the boreal region is designated as a protected area
– although all Canadian jurisdictions have enacted regulations to ensure the integrity of the
natural environment that may be impacted by anthropogenic activities – and therefore, the
metrics depicted in Figure 3.12 may not fully quantify the ecological impacts of the assessed new
hydropower generation and transmission options. For example, Figure 3.16 depicts the habitats
of the woodland caribou within the jurisdictions pertaining to this study. Woodland caribou – an
iconic species whose population is often seen as an indicator of the ecosystem health of the
boreal region – is an endangered species whose population is at risk of declining due to habitat
loss (Environment Canada, 2015b).
11
Construction period of a large hydropower plant is in the order of 10-12 years and that of transmission lines is in
the order of 1-4 years.
12
W.A.C. Bennett dam is upstream of the proposed Site C dam site on the Peace River; currently there are six
hydroelectric dams on the Nelson River upstream of the proposed Conawapa site.
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Figure 3.16 also depicts the viability of self-sustaining the boreal woodland caribou population
without conservation intervention as reported in a scientific study by Environment Canada
(2008). It can be seen that transmission ROW associated with all new hydropower options, if
developed, would impact the woodland caribou habitat. Moreover, a greater proportion of that
habitat is unable to support a self-sustaining woodland caribou population. Therefore, new
transmission development could exacerbate the risk of a declining woodland caribou population.
Figure 3.16: Woodland Caribou Population in the Study Area
Source: Environment Canada (2008); Figure by CERI
Another direct impact of hydropower development is the impact on fish habitat, populations,
migrations, and movements in general. Adverse impacts on fish population may stem from loss
of spawning sites. A hydropower plant could also impact the movement of fish within their
riparian habitat. Establishment of fish ways, allowing fish to circumvent the hydroelectric
development, is one mitigation option, although it would not enable the movement of 100
percent of the fish (Legislative Assembly of Alberta, 2013). Fish sluiceways are an adaptive means
that would allow the fish to move from the reservoir to downstream.
Development of hydropower plants and transmission lines would lead to complex social and
ecological impacts and this study provides some high-level metrics of those impacts.
Quantification of those impacts and identifying parties that would be affected is important in
developing mitigation measures, facilitating constructive stakeholder deliberations, and ensuring
fairness and equity.
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Employment and Other Economic Development Benefits
Major infrastructure projects such as the development of hydropower plants and transmission
systems contribute to economic development. Construction and operational phases of such
infrastructure projects creates a large number of direct and indirect employment. Significant
capital spending and electricity sales revenues lead to GDP growth. Contributions to different
levels of government (municipal, provincial, etc.) revenues are made in the form of taxes and
grants-in-lieu. While this study did not directly estimate those benefits, project proponents and
stakeholder organizations have provided estimates of those benefits.
For example, Manitoba Hydro estimates that development of the Conawapa hydropower plant
would create 10,700 person-years of direct and indirect employment during the construction and
operation phases. Taxes, water rental, and other fees that would be paid to the province of
Manitoba are estimated at $87.2 million per year (Manitoba Hydro, 2013).
Similarly, the Site C hydropower project is estimated to create 33,000 person-years of direct and
indirect employment during the construction phase and 160 person years of jobs per year during
the operations phase. The project is estimated to increase the provincial GDP by $3,230 million
during the construction phase and by $7 million per year in the operations phase (BC Hydro,
2013b). Water rental fees that would be paid to the province are estimated at $40.2 million/year.
School taxes and grants-in-lieu paid to local governments are estimated at $2.6 million/year.
Transmission system developments also support economic developments. An assessment by
Pfeifenberger and Hou (2011) surveyed a number of new transmission projects across North
America and it is estimated that US$1 million invested on transmission developments in Alberta
would create 10 full-time equivalent jobs during the construction phase across Canada (7 in
Alberta and 3 in the rest of Canada).
The Bipole III project in Manitoba, which would construct a 1,400 km long ±500 kV HVDC
transmission line, is estimated to create 14,392 person years of direct and indirect employment
across Canada (8,782 person years of employment in Manitoba) during the construction phase.
Operations phase employment is estimated to be 150.1 person years of direct and indirect
employment per year (Manitoba Bureau of Statistics, 2011). The Bipole III construction phase is
estimated to increase Manitoba’s GDP by $688.7 million and Canada’s GDP by $1,185 million.
Provincial tax revenue attributable to the Bipole III project is estimated to be $352.4 million
during the construction phase and $9.4 million/year during the operations phase.
Based on these facts, it can be concluded that hydropower options assessed in this study, if
developed, have the potential to contribute to local, provincial, territorial, and national economic
development.
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Chapter 4
Discussion and Concluding Remarks
The oil sands sector in Alberta is an important economic contributor to the province and Canada.
Energy-intensive extracting and upgrading of bitumen in the oil sands sector has led to high
marginal costs of production and GHG emissions. With the climate change imperative, initiatives
by various jurisdictions have exerted pressure on Alberta′s oil sands sector to reduce its GHG
emissions. This study assessed the viability of reducing GHG emissions of oil sands operations by
utilizing hydropower to satisfy its electricity demands. The study identified six options to
generate and transmit hydropower to the oil sands region, taking into account hydropower
developmental potential available in Alberta and neighbouring Canadian jurisdictions.
Each of these six options can deliver sufficient electricity to satisfy the demand of in-situ bitumen
extraction operations with production capacity of 0.5 million bbl/day to 1.1 million bbl/day. The
average cost of delivered electricity (i.e., LCOE) is in the range of $81-$162/MWh. In contrast,
utilizing natural gas-fired cogeneration units to satisfy the electricity demand would cost about
$57/MWh. To put these numbers in perspective, the average electricity pool price in Alberta
over the last 10 years has been in the range of $48-$90/MWh (AESO, 2015a). Hence, without a
price on GHG emissions, the likelihood of hydropower options reducing the marginal cost of oil
sands operations is low.
As a carbon emissions mitigation option, utilizing hydropower can potentially reduce the GHG
emissions of oil sands operations by 13-16 percent. The associated GHG emissions abatement
cost (i.e., CACO2) is in the range of $75-$332/tCO2e. The baseline assumed for the CACO2
calculation is the aforementioned cogeneration reference case. One reason for high CACO2
estimates of hydropower options is the lower LCOE and GHG emissions intensity of cogenerated
electricity.
When viewed from a different reference point such as the average Alberta grid or coal-based
generation, the abatement costs change. If the hydro project were replacing grid-based
electricity, the abatement costs range from $21/tCO2e to $137/tCO2e. If the hydropower options
are targeted at replacing coal-based generation, the costs range from minus $3/tCO2e to
$98/tCO2e. Careful consideration of the reference point is needed to properly assess the
economic cost of reducing carbon dioxide emissions.
Implications of the Alberta Electricity Market Structure on
Hydropower Project Financing
The structure of Alberta’s electricity market has implications on investments on hydropower
generation and transmission options assessed in this study. Unlike many other Canadian
jurisdictions, Alberta’s electric power system is deregulated with a competitive market in
operation for electric power generation. Within this structure, electricity that is not self-supplied
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must be exchanged through the competitive market. The AESO coordinates and operates an
energy-only market for electricity, where generators submit offers to supply electricity for each
hourly period and consumers submit bids to purchase electricity. Electricity producers receive
the hourly pool price (measured in $/MWh) for the electricity supplied. Electricity transmission
and distribution remain regulated where remunerations are set through cost of service reviews
by the Alberta Utilities Commission.
The pool price of a given hour depends on the electricity demand and generators available to
satisfy it. The minimum pool price is $0/MWh and the maximum is $999/MWh. The average
pool price in Alberta over the last 10 years has been in the range of $48-$90/MWh.
Within this market structure, there is no organized program for long-term firm electricity
contracts, although generators and consumers can negotiate power purchase agreements. As
indicated in Table 3.2, the hydropower generation transmission options assessed require massive
amounts of irreversible capital investments. Some form of investment guarantee may be needed
to assist with the development of a hydropower project for Alberta. Given the magnitude of
capital costs and operations life of hydropower plants, it is unlikely a proponent would make
investment decisions solely based on observed and forecasted pool prices in Alberta.
Alberta-British Columbia Hydropower Options
The lowest LCOE and CACO2 result from purchasing hydropower from the BC Hydro system and
delivering it by utilizing the existing transmission intertie between Alberta and BC (BC Intertie
option). This option requires implementation of mitigation measures to enable the full capacity
utilization of an Alberta-BC intertie. This option also has the advantage of being able to deliver
electricity in the short- to medium-term.
The highest LCOE and CACO2 are associated with two new BC hydropower options that assume
electricity produced by the Site C generating unit is delivered to the oils sands region utilizing a
HVDC (Site C-DC option) or HVAC (Site C-AC option) transmission system. Of the two options, the
HVAC option has the higher LCOE and CACO2.
One main factor that leads to uncertainty in the viability of importing hydroelectric power from
BC is the high forecasted electricity demand growth in BC; the BC Hydro system appears to run
into electrical energy and capacity shortages in the early 2020s. Therefore, it is uncertain
whether the BC hydropower options would be able to export large volumes of baseload
electricity into oil sands operations in Alberta.
Alberta Slave River Hydropower Options
Of the new hydropower development options assessed in this study, developing a hydropower
plant on the Alberta Slave River and connecting it to Fort McMurray (Slave River-DC option)
through a HVDC transmission system is the most attractive option in terms of LCOE and CACO2.
In contrast, the Slave River-AC option that assumes a hydropower plant on the Slave River would
be connected using two single circuit HVAC lines has higher LCOE and CACO2 estimates.
However, the difference between LCOE values is 9 percent and the Slave River-AC option has the
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added reliability result from maintaining two independent transmission corridors. The
transmission system in the latter option, however, has higher environmental impacts due to the
need for two transmission ROW.
Of all the hydropower options assessed, the Slave River-DC and Slave River-AC options would
likely have the highest amount of environmental impacts. Environmental impacts would be
exacerbated by the impacts on Wood Buffalo National Park and the Peace-Athabasca Delta, a
wetland ecosystem with global importance. Moreover, these two options would likely have
higher impacts on Indigenous populations. It should be noted that a previous attempt to develop
a hydropower plant on the Slave River did not proceed as the project proponents were unable to
reach an agreement with the Smith’s Landing First Nations, who opposed the project citing
environmental concerns (Bell, 2010).
The process to obtain the necessary regulatory approval for the Slave River-DC and Slave RiverAC options appears to be less complex than the other options as both the hydropower plant and
transmission system would be sited within the Alberta provincial boundary. However, the
permitting process would be complicated by potential impacts on federally protected
environmentally sensitive areas and the fact that hydrological changes induced by water
regulation can potentially impact the Peace River, Lake Athabasca, and the Mackenzie River
system, would concern jurisdictions both upstream (e.g., BC and Saskatchewan) and downstream
(e.g., Northwest Territories).
Alberta-Manitoba Hydropower Options
The Manitoba DC option that assumes the development of the proposed Conawapa hydropower
plant in Manitoba and connecting it to Fort McMurray by a HVDC transmission system is the most
attractive new hydropower option for Alberta hydropower developments. The Conawapa
project is in the advanced planning stage and Manitoba Hydro has already completed feasibility
assessments. The Conawapa project site is on the Nelson River, which has already been
impounded by six upstream hydroelectric dams, minimizing additional environmental impacts.
Manitoba Hydro has extensive experience with hydropower and HVDC systems that can facilitate
efficient planning, developing, and operating of the hydropower generating plant and
transmission system. The Manitoba Public Utilities Commission put the project on hold until
Manitoba Hydro secures electricity export opportunities. A long-term contract to export
electricity to the oil sands operations in Alberta can provide the level of certainty the province
needs, justifying the investment. An additional large-scale hydropower option is available on the
Nelson River downstream of the Conawapa site at the Gillam Island site. Therefore, the HVDC
system pertaining to the Manitoba DC option can be utilized to deliver additional electricity to
Alberta from the current and future hydropower plants on the Nelson River, lowering the
transmission cost as well as potentially supporting larger amounts of oil sands operations.
Siting the transmission system of the Manitoba DC option would likely be very complex in terms
of obtaining the necessary regulatory approvals. The transmission system would span across
three provinces and have higher impacts on the boreal forest than other transmission options
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assessed in this study. Another factor that would complicate the permitting is the uncertainty in
benefits to Saskatchewan. Approximately 47 percent of the transmission ROW of Manitoba DC
would lie in Saskatchewan, but the province would not receive any power sales revenues or
electricity to satisfy local demand. The transmission system, however, would create employment
in Saskatchewan during the construction and operation phases of the transmission system. It
would also contribute to Saskatchewan GDP growth as well as government revenues through
taxes (e.g., linear property taxes).
Another uncertainty about the viability of the Manitoba DC option stems from other potential
export markets Manitoba Hydro is pursuing. Historically, Manitoba exports about 30 percent of
its electricity production; more than 85 percent of that total is exported to electricity utilities in
the US Midwest region. Manitoba’s electricity export capability – determined by transmission
interconnections – is almost four times that of export capability to neighbouring Canadian
provinces. Manitoba Hydro coordinates its operations with the Midwestern US electricity market
operated by the Midcontinent Independent Systems Operator (MISO). The MISO market size, in
terms of peak demand, is 10 times that of Alberta.
As indicated in its long-term development plan, those factors have led to Manitoba Hydro
pursuing greater electricity export opportunities in the MISO region, instead of Canadian markets
such as Alberta (Manitoba Hydro, 2013). Therefore, potential development of the Manitoba DC
would require additional financial or policy considerations for this project to move forward. An
arrangement between Manitoba and Alberta would demonstrate interprovincial cooperation as
noted in the Canadian Energy Strategy (2015).
Electrical Extraction Technologies as a Carbon Management Option
Deploying electrical extraction technologies and utilizing hydroelectric power as the electricity
supply would lead to much larger emissions reductions for bitumen production. However, higher
electricity demand for electrical extraction technologies would lower the bitumen extraction
potential of the hydropower options assessed in this report. A preliminary economic assessment
conducted through scenario analysis showed that the economic feasibility of this option is tied
to the electricity intensity of the extraction process. Further research is required to gain insights
into the conditions that would make this option economically viable.
Long-term Planning
Hydropower generation and transmission options assessed in this study have the ability to
reduce GHG emissions of oil sands operations by decarbonizing the electricity consumed for
bitumen extraction and upgrading. Furthermore, those hydropower options have the ability to
contribute to provincial, territorial, and national economic development by creating employment
and increasing GDP.
Development of the hydropower plants and transmission systems require massive amounts of
irreversible capital investments. Therefore, the viability of implementation of any of the
hydropower options assessed in this study depends on providing the project developers the
certainty of capital cost recovery. Moreover, development of these hydropower plants would
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lead to environmental and socioeconomic impacts that extend beyond the jurisdictions in which
they would be sited. Therefore, greater levels of inter-jurisdiction coordination and stakeholder
consultation is vital for the successful implementation of any of these hydropower generation
and transmission options.
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Appendix A
Social and Environmental Impacts
within the Study Area
Social and environmental impacts of the respective hydropower options within the full study area
(i.e., the area formed by a combination of a 50 km wide buffer that encloses the selected
transmission line corridor and a circular buffer with a 5 km radius that encloses the hydropower
plant) are presented in Figures A.1-A.4.
Figure A.1: Land Cover of Respective Study Areas
Source: CERI
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Figure A.2: Residential and Property Value Impacts
Source: CERI
Figure A.3: Impacts on Indigenous Populations
Source: CERI
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Figure A.4: Protected Areas and Water Bodies within the Respective Study Areas
Source: CERI
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Appendix B
Calculation of Energy Cost and
Emissions of Bitumen Extraction
through SAGD
In order to estimate the cost of energy and CO2 emissions associated with bitumen extraction
through SAGD, an illustrative case example is developed. In this example, a SAGD facility with a
bitumen production capacity of 30,000 bbl/day is modeled. Electricity and thermal energy
demands of the facility are satisfied by a natural gas-fired cogeneration system and a
supplemental boiler (see Figure B.1). Excess electricity produced by the cogeneration system is
assumed to be exported to the Alberta electricity market and costs and emissions associated with
the exported electricity are subtracted from the bitumen production cost and emissions.
Figure B.1: Energy System of the SAGD Facility
Source: CERI
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Where,
FT = Fuel input to gas turbine
FG = Fuel input to HRSG
FB = Fuel input to supplementary boiler
Pc = Electricity production
PE = Exported electricity
P = Onsite electricity consumption for bitumen extraction (16.5 kWh/bbl)
HC = Enthalpy of the steam produced by the cogeneration system (HRSG)
Hcfw = Enthalpy of the HRSG feed water
HB = Enthalpy of the steam produced by the supplementary boiler
Hbfw = Enthalpy of the supplementary boiler feed water
H = Onsite thermal energy consumption for bitumen extraction (1.3 GJ/bbl)
T = Gas turbine electricity generation efficiency (30%)
R = HRSG heat recovery efficiency (50%)
G = HRSG supplemental firing efficiency (95%)
B = Supplementary boiler efficiency (85%)
(All efficiencies are higher heating value basis)
Fuel and emissions attributable to electricity are calculated as follows (Doluweera et al., 2011):
𝐹𝑢𝑒𝑙 𝑎𝑡𝑡𝑟𝑖𝑏𝑢𝑡𝑎𝑏𝑙𝑒 𝑡𝑜 𝑒𝑙𝑒𝑐𝑡𝑟𝑖𝑐𝑖𝑡𝑦, 𝐹𝐶𝐸 =
𝐹𝑇 +𝐹𝐺 −(𝐻𝐶 −𝐻𝑐𝑓𝑤 )⁄𝜂𝐵
𝑃𝐶
𝐸𝑚𝑖𝑠𝑠𝑖𝑜𝑛𝑠 𝑎𝑡𝑡𝑟𝑖𝑏𝑢𝑡𝑎𝑏𝑙𝑒 𝑡𝑜 𝑒𝑙𝑒𝑐𝑡𝑟𝑖𝑐𝑖𝑡𝑦, 𝐼𝑒𝑙 = 𝐹𝐶𝐸 ×
𝐶𝑂2 𝑒𝑚𝑖𝑠𝑠𝑖𝑜𝑛𝑠 𝑖𝑛𝑡𝑒𝑛𝑠𝑖𝑡𝑦 𝑜𝑓 𝑛𝑎𝑡𝑢𝑟𝑎𝑙 𝑔𝑎𝑠
The average cost of thermal energy is assumed to be that of a natural gas-fired boiler with the
same attributes as the supplemental boiler and are calculated as follows:
𝐴𝑣𝑒𝑟𝑎𝑔𝑒 𝑐𝑜𝑠𝑡 𝑜𝑓 𝑡ℎ𝑒𝑟𝑚𝑎𝑙 𝑒𝑛𝑒𝑟𝑔𝑦, 𝐶𝑡ℎ =
𝐵𝑜𝑖𝑙𝑒𝑟 𝐶𝐶 × 𝑐𝑐𝑓+𝑓𝑖𝑥𝑒𝑑 𝑜𝑝𝑒𝑟𝑎𝑡𝑖𝑛𝑔 𝑐𝑜𝑠𝑡+𝑎𝑛𝑛𝑢𝑎𝑙 𝑓𝑢𝑒𝑙 𝑐𝑜𝑠𝑡
𝐴𝑛𝑛𝑢𝑎𝑙 𝑡ℎ𝑒𝑟𝑚𝑎𝑙 𝑒𝑛𝑒𝑟𝑔𝑦 𝑝𝑟𝑜𝑑𝑢𝑐𝑡𝑖𝑜𝑛
Average cost of electricity of the cogeneration system is calculated after adjusting for thermal
energy production as follows:
𝐴𝑣𝑒𝑟𝑎𝑔𝑒 𝑐𝑜𝑠𝑡 𝑜𝑓 𝑒𝑙𝑒𝑐𝑡𝑟𝑖𝑐𝑖𝑡𝑦, 𝐶𝑒𝑙 =
𝐶𝑜𝑔𝑒𝑛 𝐶𝐶 × 𝑐𝑐𝑓+𝑓𝑖𝑥𝑒𝑑 𝑜𝑝.𝑐𝑜𝑠𝑡+𝑎𝑛𝑛𝑢𝑎𝑙 𝑓𝑢𝑒𝑙 𝑐𝑜𝑠𝑡−𝐶𝑡ℎ × 𝑎𝑛𝑛𝑢𝑎𝑙 𝑡ℎ𝑒𝑟𝑚𝑎𝑙 𝑒𝑛𝑒𝑟𝑔𝑦 𝑝𝑟𝑜𝑑𝑢𝑐𝑡𝑖𝑜𝑛
𝐴𝑛𝑛𝑢𝑎𝑙 𝑒𝑙𝑒𝑐𝑡𝑟𝑖𝑐𝑖𝑡𝑦 𝑝𝑟𝑜𝑑𝑢𝑐𝑡𝑖𝑜𝑛
Average energy cost and emissions per barrel of bitumen are calculated as follows:
𝐴𝑣𝑒𝑟𝑎𝑔𝑒 𝑒𝑛𝑒𝑟𝑔𝑦 𝑐𝑜𝑠𝑡 𝑝𝑒𝑟 𝑏𝑏𝑙 =
(𝐶𝑜𝑔𝑒𝑛 𝐶𝐶+𝑆𝑢𝑝.𝑏𝑜𝑖𝑙𝑒𝑟 𝐶𝐶)×𝑐𝑐𝑓+𝑐𝑜𝑔𝑒𝑛 𝑓𝑖𝑥𝑒𝑑 𝑜𝑝.𝑐𝑜𝑠𝑡+𝑠𝑢𝑝.𝑏𝑜𝑖𝑙𝑒𝑟 𝑓𝑖𝑥𝑒𝑑 𝑜𝑝.𝑐𝑜𝑠𝑡+
(
)
𝑎𝑛𝑛𝑢𝑎𝑙 𝑐𝑜𝑔𝑒𝑛 𝑓𝑢𝑒𝑙 𝑐𝑜𝑠𝑡+𝑎𝑛𝑛𝑢𝑎𝑙 𝑠𝑢𝑝.𝑏𝑜𝑖𝑙𝑒𝑟 𝑓𝑢𝑒𝑙 𝑐𝑜𝑠𝑡− 𝐶𝑒𝑙 ×𝑎𝑛𝑛𝑢𝑎𝑙 𝑒𝑙𝑒𝑐𝑡.𝑒𝑥𝑝𝑜𝑟𝑡𝑠
𝐴𝑛𝑛𝑢𝑎𝑙 𝑏𝑖𝑡𝑢𝑚𝑒𝑛 𝑝𝑟𝑜𝑑𝑢𝑐𝑡𝑖𝑜𝑛
(𝐹𝑇 +𝐹𝐺 +𝐹𝐵 −𝐹𝐶𝐸×𝑃𝐸 ) ×𝐶𝑂2 𝑒𝑚𝑖𝑠𝑠𝑖𝑜𝑛𝑠 𝑖𝑛𝑡𝑒𝑛𝑠𝑖𝑡𝑦 𝑜𝑓 𝑛𝑎𝑡𝑢𝑟𝑎𝑙 𝑔𝑎𝑠
𝐴𝑣𝑒𝑟𝑎𝑔𝑒 𝐶𝑂2 𝑒𝑚𝑖𝑠𝑠𝑖𝑜𝑛𝑠 𝑝𝑒𝑟 𝑏𝑏𝑙 =
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𝐵𝑖𝑡𝑢𝑚𝑒𝑛 𝑝𝑟𝑜𝑑𝑢𝑐𝑡𝑖𝑜𝑛
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The main parameter assumptions and results of the illustrative example are listed in Table B.1.
Table B.1: Main Parameters and Results of the Illustrative Case Example
Parameter
Assumptions
Bitumen production capacity
Steam to oil ratio
Thermal energy demand of bitumen extraction
Electricity demand of bitumen extraction
Annual production capacity utilization
Cogeneration system
Electricity production capacity
Steam production capacity
Heat to power ratio
Electricity generation efficiency, T
HRSG heat recovery rate, R
HRSG supplemental firing efficiency, G
Total capital requirement
Fixed operating costs
Supplementary boiler
Steam production capacity
Efficiency
Total capital requirement
Fixed operating cost
Natural gas price
Natural gas carbon emissions intensity
Capital charge factor
Results
Average cost of electricity
Average cost of thermal energy
Average energy cost per bbl of bitumen
Emissions attributable to electricity
Average emissions per bbl
Value
30,000 bbl/day
3
1.3 GJ/bbl
16.5 kWh/bbl
85%
85MW
918 GJ/h
3
30%
50%
95%
$2071/kW
$14/kW/y
707 GJ/h
85%
$17,240/(GJ/h)
$0.05/GJ
$4/GJ
53 kgCO2e/GJ
10.61%
$55/MWh
$3.9/GJ
$5.9/bbl
325 kgCO2/MWh
67 kgCO2/bbl
Source: CERI
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Appendix C
Uncertainty Analysis of LCOE and CACO2
An uncertainty analysis of LCOE and CACO2 estimates is conducted by developing a Monte Carlo
simulation (MCS). For the MCS, capital costs (both generation and transmission systems),
capacity factors, natural gas price, and electricity price at the Mid-C electricity hub are sampled
from their distributions. Each parameter is assumed to be uniformly distributed within the
identified uncertainty range as follows:





Capital cost of power plants
o Cogeneration, Site C (Site C-DC/Site C-AC), Conawapa (Manitoba DC): -15 percent
to +30 percent of the base case estimates (Table 3.2)
o Slave River (Slave River-DC/Slave River-AC): -20 percent to +50 percent of the base
case estimates (Table 3.2)1
Capital cost of transmission system: -15 percent to +30 percent of the base case estimates
Capacity factor: -30 percent to +30 percent of the base case estimates
Natural gas price: $3/GJ to $8/GJ
Mid-C electricity price: $26/MWh to $83/MWh2
Each parameter is sampled 100,000 times and the LCOE and CACO2 are calculated. Cumulative
probability distributions of LCOE of each option are depicted in Figure C.1. Cumulative
probability distributions of LCOE are depicted in Figure C.2. Similarly, cumulative probability
distributions of CACO2 are depicted in Figure C.3. The following metrics are calculated using MCS
results and are listed in Table C.1.


LCOE and CACO2 estimates that correspond to cumulative probability of 50 percent
(henceforth referred to as P50 estimates). P50 estimates of a given metric is the value
that the relevant metric, based on 50 percent probability, will not exceed
Probability of CACO2 being less than $100/tCO2e and $200/tCO2e (i.e., P(CACO2<100) and
P(CACO2<200)
1
Slave River capital cost is varied over a wider range (-15% to 50%) as the project is in the exploratory stage and
reliable capital cost estimates are not available.
2
The range used for the MCS is the monthly average peak period electricity prices observed in the Mid-C exchange
over the period 2009-2014
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Figure C.1: Monte Carlo Simulation Results: Distributions of LCOE
Notes: The boxes depict the plausible range of LCOE of different electricity generation and transmission options
when the uncertainty associated with the main parameters are taken into account. In a given box, the bottom and
top edges of the boxes correspond to the 25th and 75th percentile, respectively. The solid horizontal line inside the
box corresponds to the median. The whiskers extend to the maximum/minimum plausible value that is within 1.5
times the interquartile range from the top/bottom edge of the box. Outlier data points are marked as ‘o’.
Source: CERI
Figure C.2: Monte Carlo Simulation Results: Cumulative Distributions of LCOE
Notes: Cumulative distribution of a given option indicates the likelihood of LCOE estimates when the parameter
uncertainty is taken into account. The dotted horizontal line corresponds to P50 estimate of LCOE. MCS results
reiterate the fact that, without a price on carbon, the likelihood of the hydropower options yielding a lower LCOE
than the cogeneration reference option is low.
Source: CERI
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Figure C.3: Monte Carlo Simulation Results: Cumulative Distributions of CACO2
Notes: The dotted horizontal line corresponds to P50 estimate of CACO2. When the uncertainty associated with
major parameters is taken into account, the CACO2 of the Slave River-DC option (Slave River hydropower plant with
HVDC transmission) and Manitoba DC option (Conawapa hydropower plant with HVDC transmission) are
indiscernible. A similar result was observed for LCOE for those two options.
Source: CERI
Table C.1: Selected Metrics of Uncertainty Assessment Results
Metric
P50 estimates
LCOE ($/MWh)
CACO2 ($/tCO2e)
P(CACO2<100) (%)
P(CACO2<200) (%)
Reference
Case
Site CDC
Slave
River-DC
Manitoba
DC
Site CAC
Slave
River-AC
BC
Intertie
63
146
264
0
15
127
201
3
49
128
204
0
48
168
334
0
0
139
237
0
30
100
118
17
100
Source: CERI
The MCS results show that, under the assumed conditions, without a price on carbon emissions,
the likelihood of LCOE of the cogeneration option being higher than the hydropower option is
negligible. Site C-DC and Site C-AC options continue to be the most expensive options and the
likelihood of either of the options having lower LCOE or CACO2 than other options is negligible.
Under point estimates (Table 3.2), of all hydropower options, the BC Intertie option had the
lowest LCOE and CACO2. It is the only hydropower option that has a non-negligible probability
(17 percent) of having a CACO2 less than $100/tCO2e. However, when the uncertainty associated
with the parameters is taken into account, there is about a 10 percent probability that the Slave
River-DC option would have lower LCOE and CACO2 than the BC Intertie.
Another observation is that as far as the distributions of LCOE and CACO2 are concerned, the
Slave River-DC and Manitoba DC options are indiscernible. The probability of one being preferred
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over the other is approximately 50 percent. Furthermore, the difference between P50 estimates
of LCOE and CACO2 of the two options is only about 1 percent and 1.5 percent, respectively.
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