Long Duration Energy Storage(LDES) Opportunity Assessment
A Critical Component in Growing Ontario's
Clean Energy Economy
Prepared for:January 2024

Report by:AboutEnergy Storage Canada (ESC) is the only national tradeassociation in Canada dedicated solely to the advancementand development of the energy storage industry. Working
with our diverse members and partners, we ensure energy
storage is a vital consideration for policy and decisionmakers across Canada, with the aim of creating a reliable,
sustainable, and affordable electricity grid. Our continued
advocacy has positioned the organization as a leader for theindustry across Canadian jurisdictions.
Our goal is to drive the development of viable markets, raiseawareness regarding the opportunities and benefits storage
provides, and ensure regulatory fairness for all energy
storage technologies. With nearly 90 members to date, we
represent the end-to-end value chain of Canada’s energy
storage industry and our technology agnostic approachprovides broad support through collaboration, education,
advocacy, and research at all levels, for all energy storage
technologies.
For more information aboutwww.energystoragecanada.org

ESC,

pleasevisit

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Executive Summary
Ontario's electricity demand is expected to grow significantly through 2050, driven by
economic growth and the need to transition the province to a net-zero economy. To reach net
zero, there is a consensus amongst stakeholders that Ontario must decarbonize the existing
electricity supply and scale up non-emitting generation as much as 2 to 3 times the current
levels by 2050.
As Ontario’s generation mix and demand profile continues to diversify and evolve, so will thechallenges of balancing and delivering power to a growing provincial economy. A criticalcomponent of this system transformation will be integrating energy storage systems(ESS) featuring a variety of storage technology types. Ontario is already recognized as anational leader in ESS adoption, a reputation earned through a decade of ongoing market
reforms and initiatives culminating in 2023 with the procurement of 880 MW of storage
capacity by the Independent Electricity System Operator (IESO). By mid-decade, Ontario is
expected to see over 2,500 MW of energy storage capacity installed throughout the province.
There is growing recognition that Long Duration Energy Storage (LDES) – energy
storage systems that can discharge for over 10 hours at their maximum power rating
and act as a low or zero-carbon energy source – have a potential role in decarbonizing
Ontario’s energy system. The government of Ontario has recently taken steps to advancethe exploration of two pumped storage projects and requested further input from the IESO
on the need for LDES capacity as a prelude to potential future procurements. While several
studies have assessed the feasibility of achieving net zero for Ontario's electricity system
considering a range of emerging clean technologies, the explorations have been fairly
limited in the scope and depth of consideration of LDES technologies.
This report explores through a high-level analysis the potential role and benefits that
LDES can contribute to Ontario’s electricity system by reducing potential supply,
planning, and deployment risks associated with the pathway to net zero. For thisanalysis, we focus on the IESO’s Pathways to Decarbonization (P2D) study as it represents themost robust vision put forward to date by the system operator.

Our initial assessment suggests that deploying up to 6 GW
of Long-Duration Energy Storage (LDES) starting in 2032
could be a cost-effective solution to mitigating potential
supply, planning, and deployment risks on Ontario’s
pathway to net zero.
Specifically, the study explores the potential role LDES can play under three scenarios:•

Scenario 1 - Buildout Risk: Uncertainty around the pace of deployment of new nuclear
assets and hydrogen turbines creates long-term capacity needs.

•

Scenario 2 – Hydrogen Supply Risk: New nuclear assets are assumed to be deployed at
the pace and scale outlined in the P2D. However, supply chain issues around blue

Energy + Climate Advisorsbuildings ∙ mobility ∙ industry ∙ energyihydrogen supply (as outlined in the P2D) result in limitations on the deployment ofhydrogen-powered turbines.
•

Scenario 3 – Planning and Procurement Risk: New nuclear assets are assumed to be
deployed at the pace and scale outlined in the P2D. However, import capacity constraints,
limited contracting of existing assets and higher-than-expected peak demand contributeto higher capacity shortfalls.

Under these scenarios, increased natural gas-fired electricity generation is the most likely
backstop for managing the risk of capacity shortfall in Ontario. Relying on natural gas as a key
backstop and risk management tool on the path to net zero has potentially significant
economic and environmental implications, ranging from commodity price volatility to runningafoul of nationally mandated emissions reduction targets.
Our high-level analysis focuses on the assessment of the benefit-cost of LDES deployments
under each scenario to estimate the magnitude of cost-effective LDES deployments that canmaintain the affordability and reliability of Ontario’s future electricity system should theserisks unfold. Up to 6 GW of LDES were found to be cost-effective across all three scenarios.
This increases to up to 10 and 18GW under scenarios 2 and 3, respectively, if capacity
shortfalls exacerbate further.

Cost Effective LDES Procurement by 2032

Benefit-Cost Ratio

Cost-Effective
Scenario 3

10 GW

Cost- Effectiveness

18 GW threshold

6 GW

Not Cost Effective
2 GW

4 GW

6 GW

8 GW

10 GW

12 GW

14 GW

16 GW

Scenario 1
Scenario 2

18 GW

Magnitude of LDES Deployment by 2032
Figure A: Range of LDES procurement in Ontario

While recognizing that the use of hydrogen turbines in the pathway outlined in the P2D is a
proxy of the need for a wider range of gas peaker replacement options, we identify that LDES
powered by wind is a cost-effective alternative for ensuring and maintaining grid reliability
during this transition and therefore merits closer attention.

Our high-level analysis suggests that deploying 6 GW of
LDES could provide between $11B to $20B in ratepayer
savings over its lifetime relative to the baseline P2D
scenario.

Energy + Climate Advisorsbuildings ∙ mobility ∙ industry ∙ energyiiIn summary, our initial assessment suggests that LDES can be an important risk
management tool as Ontario pursues its pathway to a net-zero electricity system.
Indeed, LDES can serve as a reliable backstop for capacity shortfalls and a key provider of abroad range of grid ancillary services to support reliability while also providing increased
operational flexibility and support during contingency events.

Given the potential benefits to Ontario and the timelines
inherent in procuring LDES options, further analysis isnecessary to define the potential, set appropriate targets,and advance timely procurements.
As an immediate, no-regrets move, the IESO can begin incorporating LDES into all
future planning and explore in greater depth the potential of distinct LDES options todeliver grid benefits, including enhancement of resource adequacy, operating reserves,
regulations compliance, and emission reductions. The thorough exploration of LDES would
then enable the IESO to establish an appropriate LDES procurement target for Ontario,
taking into account all the costs and benefits, including the mitigation of potential risks
associated with a slower build-out of new resource options, insufficient hydrogen supply
and/or unforeseen planning and recontracting risks that may result in inadequate supply fromexisting resources.
The outcomes of this exploration can inform the establishment and communication ofclear targets for LDES deployment in Ontario from 2030 through 2050, as well as for
procurements starting mid-decade. Considering the challenges of abbreviatedprocurement lead times (e.g. community consent, supply chain constraints), the prospect offirst-of-a-kind permitting processes, the longer lead times required for many LDES
technologies (estimated to up to seven years), as well as the sunset of the 30% Federal
Investment Tax Credit (ITC) by 2033, clarity on timelines and early procurement calls – starting
as early as 2025 will be critical to unlocking the full contribution of LDES towards a resilient,
low-emission, and economically vibrant Ontario.

Energy + Climate Advisorsbuildings ∙ mobility ∙ industry ∙ energyiii

Contents
Executive Summary .................................................................................................i
1. Introduction..................................................................................................... 1
2. Technology ...................................................................................................... 3
2.1 Classifications ....................................................................................................................................... 3
2.2 Technical Readiness ............................................................................................................................. 4
2.3 Cost Competitiveness .......................................................................................................................... 7

3. The Need for LDES .......................................................................................... 9
3.1 Ontario’s Net Zero Pathways ............................................................................................................... 9
3.2 LDES in Net Zero Pathways Studies ................................................................................................. 10
3.3 Risks in Pathways to Net Zero ........................................................................................................... 12

4. The Value Proposition ................................................................................... 17
4.1 Modeled Scenarios ........................................................................................................................... 17
4.2 Key Results ......................................................................................................................................... 19
4.3 Key Takeaways ................................................................................................................................... 31
4.4 Additional Benefits ............................................................................................................................ 33

5. Recommendations ........................................................................................ 35
Appendix A: LDES Technology ........................................................................... A-1
Appendix B: Analytical Approach ...................................................................... B-1

1. Introduction
Ontario's electricity demand is expected to grow significantly until 2050, driven bysustained population and economic growth. Additionally, to mitigate the impacts ofclimate change and retain our economic competitiveness, the province needs to transition toa net-zero economy that significantly reduces greenhouse gas (GHG) emissions and increases
reliance on cleaner energy sources. This will require the economy-wide decarbonization ofbuildings, transportation, industry, and energy supply. Furthermore, as heating,transportation, and a range of heavy and light industries transition from fossil fuels to electricalternatives, Ontario will see significantly higher electricity demand. Thus, the province’s
electricity grid will be the crucial enabler of the province’s transition to a net zero economy.
To reach net zero, the consensus amongst stakeholders and of system modellingindicates that Ontario must decarbonize its existing electricity supply and scale up
generation to 2 to 3 times current levels by 2050. Several studies1 have evaluated netzero-aligned pathways for decarbonizing Ontario's electricity system. The range of solutions
found in these analyses includes improvements in energy efficiency, significant expansion ofrenewable generation, deployment of large-scale nuclear and SMRs, use of hydrogenpowered turbines, and a large-scale expansion of the medium- and high-voltage transmission
network.
Different pathways envision different mixes within these solutions, but all are highly
sensitive to the assumptions underlying the analysis, and thus, each potential pathway
carries inherent risks. These uncertainties include the pace and magnitude of the
deployment of technologies such as SMRs, hydrogen turbines or even the scale of electricity
demand. Uncertainty equals risk. The risk that potential pathways may not unfold as
envisioned has potential implications for the affordability and reliability of Ontario’s future
electricity system.
Ontario must design a clear risk mitigation strategy. Currently, the most likely backstop for
managing such risk in Ontario is increased natural gas-fired electricity generation2. This is not
ideal, given that increased natural gas-fired generation works against the necessity todecarbonize the grid. It is also unclear whether new natural gas-fired generation builds
represent the most cost-effective way3 to ensure grid reliability should Ontario be forced todeviate from its planned path forward on decarbonization.
Relying on natural gas as a principal backstop and risk management tool on the path tonet zero has potentially significant economic and environmental implications.
Economically, it increases exposure to volatile prices and the risk of stranded assets, limiting
the potential for low-cost renewable energy and nuclear as alternative energy sources when

Outlined in Section 3: The Need for LDESOn November 16th, the IESO published its response to the Federal government’s draft Clean Electricity
Regulation (CER). In its response, the IESO states that “it plays a critical role in maintaining system reliability” andthat “reduction in natural gas is enabled by nuclear refurbishments, new small modular reactors, other additional
renewable generation (e.g., wind, solar) and significant conservation.” Thus, any threat to grid reliability would
position natural gas as the most likely backstop.
3
When paired with battery storage, wind and solar can offer dispatchable grid power at increasingly morecompetitive costs than gas peakers in Ontario. A Renewables Powerhouse - Clean Energy Canada
1
2

Energy + Climate Advisorsbuildings ∙ mobility ∙ industry ∙ energy

1paired with storage to ensure reliability. Environmentally, aside from direct emissions, there isa risk of indirect emissions resulting from methane leakage during transportation andextraction4. Carbon capture and storage (CCS) of carbon emissions remains a promising but
unproven technology5. If Ontario ends up pursuing a strategy contingent on increased
natural gas use, it ensures that net zero will not be achieved and risks a high-cost outcome.
Therefore, a critical component of this system transformation will be integrating energy
storage systems (ESS) featuring a variety of storage technology types. Ontario is alreadyrecognized as a national leader in ESS adoption, a reputation earned through a decade ofongoing market reforms and initiatives culminating in 2023 with the procurement of 880 MWof storage capacity by the Independent Electricity System Operator (IESO). By mid-decade,Ontario will see over 2,500 MW of energy storage capacity installed across the province.
As Ontario’s generation mix and demand profile continues to diversify and evolve, so will thechallenges of balancing and delivering power to a growing provincial economy. Several
studies have assessed the feasibility of achieving net zero for Ontario's electricity system withconsideration for a range of emerging clean technologies, but until now, most have had afairly limited scope and depth of exploration of the potential role of Long Duration Energy
Storage (LDES) – energy storage systems that can discharge for over 10 hours at its maximum
power rating and act as a low or zero-carbon energy source.
In particular, as relatively flat winter peak trends unfold, LDES can be a critical component inshaping transition pathways by firming low-cost variable generation sources like wind andsolar energy and supporting baseload resources like nuclear and hydro as reliable resources
for meeting capacity needs and key provider of an array of grid ancillary services to support
reliability and increased operational flexibility and support during contingency events.
This report, then, examines the potential of LDES technologies to reduce risks and ensure
success as Ontario continues its transition to net zero. Specifically, the study:•

Highlights the Technology Readiness of LDES by exploring the range of LDES
technologies and their corresponding technical maturity and commercial availability.

•

Identifies The Need for LDES by evaluating the supply, deployment, and planningrisks in the various net-zero pathways explored to date.

•

Demonstrates The Value Proposition LDES offers the system through high-level
modelling, which confirms LDES is a cost-effective guardrail to ensure that Ontario
stays on track toward its decarbonization goal.

•

Provides Recommendations for Ontario’s electricity sector stakeholders to capture
the benefits associated with LDES.

Canada’s second most abundant greenhouse gas is CH4, making up 13% of national GHG emissions. In 2018,
43% of Canada’s anthropogenic CH4 emissions originated from oil and gas systems. The major sources of oil andgas CH4 emissions are from activities that occur during upstream production, which include venting (intentional
releases; ~ 52%), incomplete combustion during flaring (~ 1.4%), and fugitive emissions (unintentional releases
from faulty equipment, or drilling; ~ 42%) MacKay, K., Lavoie, M., Bourlon, E., Atherton, E., Baillie, J., Fougère, C.,& Risk, D. (2021). Methane emissions from upstream oil and gas production in Canada are underestimated.
Scientific Reports, 11(1), 1-8. https://doi.org/10.1038/s41598-021-87610-3
5
The P2D also raised concerns about CCS, indicating that carbon capture and storage CCS was considered
unlikely given the technical and economic challenges of using it on peaking plants.
4

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22. Technology
Long-duration energy storage or LDES typically refers to an energy storage system thatcan discharge for 10 hours or more at its maximum power rating to act as a firm low orzero carbon energy source6. These technologies differ from other battery storage systems
that discharge over much shorter durations. LDES technologies can serve many purposes
when integrated into a grid, providing operating reserves, peaking capacity, multi-day
storage, and even seasonal energy storage.

2.1 Classifications
LDES systems and technologies come in many shapes and sizes but are broadly categorized
as electrochemical, mechanical, or thermal7. Each category can be subdivided further, butthese broad categories help explain the fundamental technologies, inputs, supply chains, andgrid-supporting use cases.
•

Electrochemical LDES includes technologies such as static, flow, or metal anodebatteries. Some of these can include zinc-bromine hybrid flow, aqueous zinc halide,aqueous vanadium redox flow, aqueous symmetric sodium ion membranes, calcium
anodes, nickel-hydrogen anodes, iron flow anodes, zinc anodes, zinc-air, iron-air
anodes, iron-salt anodes, and many others. Electrochemical LDES has the widest
variety of options for the technology configuration, and new systems are frequently
coming to market. Electrochemical batteries are easily scalable, have long life cycles,
are unaffected by deep discharges, and can have very low self-discharge.

•

Thermal LDES systems use stored thermal energy, which can be used most forbuilding heating and industrial processes. Latent heat can be captured through solidto-liquid transformation, sensible heat in a single medium, and thermochemical heatfrom endothermic and exothermic reactions. The medium and materials used – suchas salts, graphite, water, solid and liquid metals, and waxes – offer various temperature
ranges, storage durations, and use cases. These systems are low-cost due toabundant, inexpensive raw materials and, in some cases, incredibly high energy
densities. Further, the energy capacity of the thermal LDES systems can also be
extended by increasing the amount of storage material and is independent of thesystem's power capacity.

•

Mechanical systems take a very different form and employ water, air, or heat incompression systems or turbines, using gravity or pressure to store energy for longer
durations. The most well-established LDES technologies include pumped hydrostorage, which accounts for 95% of total energy storage capacity worldwide today, as

According to a literature survey carried out by NREL, using +10 hours is an ideal definition for long-durationenergy storage (LDES). This is because it has the largest number of citations across the studies surveyed by NREL
and is increasingly being used after its adoption by the Advanced Research Projects Agency-Energy (ARPA-E),
which defines LDES as 10–100 hours. NREL LDES Survey
7
Some classifications of LDES include a fourth category, chemical, to refer to energy-carrying chemicals or fuelssuch as hydrogen or natural gas. These are not considered within this report.
6

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3well as compressed air storage that can be held above- or underground. However,other systems, such as liquid CO2 and liquid air energy storage, allow for energy
storage through high pressure and/or low temperatures.

2.2 Technical Readiness
Different types of LDES systems are at different levels of technological readiness. Some are
already widely available and commercially used, while others are still in the pilot anddemonstration phases or are being researched and developed. These technologies aredeveloping quickly, with pilots and demonstrations advancing to commercialization more
rapidly than in previous years. Broadly, there are three stages of technical readiness8:
1. Established LDES Technologies: Pumped hydro and compressed air are well-establishedmechanical-based LDES technologies. Although there can be some challenges regarding
siting and permitting, the technology, expertise, and supply chains are globally available
and established. Additionally, flow batteries have gained wide-scale acceptance among
electrochemical technologies and are commercially available around the world, withmany projects announced and under construction9. Latent heat systems have also been
deployed worldwide, primarily for industrial energy storage.
2. LDES in the pilot and demonstration phase: This intermediate stage signifies theongoing transition from theoretical viability to practical application. The progression fromthe pilot and demonstration phase to full-scale deployment is driven by market demand,
regulatory support, and heightened awareness of the importance of long-duration energy
storage. As a result, stakeholders are closely monitoring the performance of thesetechnologies for scaling them up for broader implementation in the energy landscape.
The technologies include hydrogen storage, liquid air energy storage, zinc-based
batteries, and molten salt technologies.
3. Research and Development Stage: These technologies were recently in research anddevelopment. Many thermal energy storage systems are still in the pilot phase andseeking funding for demonstration projects. Start-ups and laboratories are exploring
many other options for liquid metal energy storage. Sensible heat is an energy storage
technology in the R&D phase, using molten salts and rocks. Metal anode batteries areanother category of LDES technology recognized as having grid-scale deployment
potential.
While the classification above clarifies the different stages of market readiness for LDES froma technical perspective, these technologies also differ in their technical qualifications,
including size, capacity, and efficiency, as shown in Table 1 in Appendix A.

Technical Readiness Levels (TRLs) is a method for understanding the technical maturity of a technology. This
report categorized technologies into three stages based on their Technology Readiness Level (TRL). The Researchand Development Stage includes all technologies with a TRL of 1 to 6. The Pilots and Demonstration Stage
includes all TRL 6 and TRL 8 technologies. Finally, technologies with a TRL of 9 are categorized under theCommercial Stage. Technology Readiness Level (TRL) Assessment Tool (canada.ca)
9Net-Zero Power Report
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4Regardless, LDES development and deployment are gaining momentum. This growth isfueled by major government agencies such as the US Department of Energy and California’s
Energy Commission, major utilities, research labs, and investors. Overall, the technicalmaturity and commercial readiness of LDES technologies are driven by three fundamental
factors:
1. The validation of the role of LDES technologies through pilot and demonstration
programs: Utilities around the world are currently testing and piloting LDES
technologies to improve reliability and resource adequacy and enable greater
integration of renewable energy sources. LDES technology providers also leveragethese pilots and demonstrations to enhance their technologies and increase technicaland manufacturing readiness. Some note-worthy programs targeted at LDES include,•

NYSERDA’s Renewable Optimization and Energy Storage Innovation Program
has set aside $16.6 million for five projects demonstrating long-duration
storage technologies. These projects aim to integrate renewable energy
sources and reduce emissions. Furthermore, an additional $17 million has
been allocated to procure more LDES projects that address cost,
performance, siting, and renewable integration challenges.

•

At the federal level, the US Department of Energy has also launched theLong Duration Storage Shot, part of the Earthshots program, which aims to
reduce the cost of long-duration energy storage by 90% within ten years,
which has $1.16 billion allocated for the program.

2. The establishment and consideration of procurement targets for LDES: Several
jurisdictions, including California and New South Wales in Australia, have alreadyestablished procurement targets for long-duration energy storage. States such as New
York, Michigan, and Minnesota have also recognized the necessity of incorporating
long-duration energy storage in their system planning.

10
11

•

California PUC has set a target of 1000 MW of long-duration energy
storage by 2028 and invested over $380 million in the Long Duration Energy
Storage Program to support the commercialization and demonstration of
long-duration energy storage systems10.

•

In the 2022 Electricity Statement of Opportunities (ESOO) report, theAustralian Energy Market Operator (AEMO) emphasized the urgent
need to procure 2000 MW of long-duration storage in New South Walesby 2029 to mitigate reliability risks11.

California Energy Commission, Long Duration Energy Storage Program
AEMO Update

Energy + Climate Advisorsbuildings ∙ mobility ∙ industry ∙ energy5•

New York's Energy Storage Roadmap12 established a requirement for
long-duration energy storage. The analysis completed for Roadmap
identified a need for 24 GW of 100-hour battery-type storage with 50%
round-trip efficiency to replace the contributions of 18 GW of a fully
dispatchable hydrogen-based resource, along with 13 GW of incremental instate renewable resources to provide additional energy to charge thisstorage resource.

•Michigan has introduced bill HB 4256 that mandates that the Michigan PublicService Commission conduct a study to determine the amount of longduration energy storage required in Michigan and to establish targets for
procuring the necessary long-duration storage.

3. The improvement of access to financing and technical resources for LDES
providers: Most providers of LDES technology either use conventional components
like turbines, compressors, heat exchangers, and pumps or base their technology
solutions on minerals like Zinc and Iron that are readily available. As a result, mineral
extraction companies, turbine and engine manufacturers, large-scale developers, andutilities often partner with LDES companies to provide technical and financial support.
As the partnerships expand, so does the sector’s ecosystem, leading to increased
connectedness. This, in turn, promotes experimentation, knowledge sharing, andcoordination on investments, unlocking the potential driving the industry's technicaland commercial maturity. With more technology providers trying to develop
technologies in this space, the technical understanding and workforce needed to
deploy LDES continue to grow.
•Partnerships with Extraction Companies: LDES companies such as Form
Energy and VRB Energy13 have established key relationships with raw
material suppliers to improve their commercialization prospects. Mineral
extraction companies assist LDES companies by ensuring a secure supply
chain, minimizing supply disruptions, and providing financial support tobridge funding gaps.

•

Venture Capital Support: Venture capital plays a critical role in elevating thecompetitiveness of long-duration energy storage (LDES) by offering essential
financial backing for research, development, and implementation. Leading
VC funds, including Breakthrough Energy Ventures, Energy Foundry, and theEuropean Investment Bank, are instrumental in expediting the market entry
of innovative LDES solutions.

New York’s 6 GW Energy Storage Roadmap: Policy Options for Continued Growth in Energy
Storage. The study suggests that New York's electric grid may need other forms of long-duration energy storage ifhydrogen-based or zero-carbon fuel-based resources are unavailable, too expensive, or infeasible to build incertain locations.
13
Cooperation Framework Agreement between VRB Energy and Pangang
12Energy + Climate Advisorsbuildings ∙ mobility ∙ industry ∙ energy

62.3 Cost CompetitivenessTo examine the cost competitiveness of LDES technologies, five alternative technologies werecompared to 10-hour long-duration energy storage (including lithium-ion) on a net capacity
cost basis14. As seen in Figure 1, the net capacity cost of LDES technologies15 is comparable
to that of combined cycle natural gas, combined cycle natural gas with carbon capture,
natural gas peakers, and small modular reactors (SMRs). Among the assessed technologies,
the net capacity cost of hydrogen peakers is the highest.

Capacity Value ($/kW-yr)

LDES is comparable on capacity value compared to alternatives
$600
$500
$400
$300
LDES
CCGT
CCGT-CCS
Gas Peaker
Green H2 Peaker
SMR

$200
$100

$0
2025 2026 2027 2028 2029 2030 2031 2032 2033 2034 2035
Figure 1 Net Capacity Costs of LDES vs Alternatives16

Net Capacity Cost Calculation: Net capacity cost refers to the annual revenue needed tocover a new capacity resource's capital and fixed costs (net of market revenues) over its
lifetime. To determine the net capacity cost of a generation asset, we begin by calculating
the gross lifetime costs. This includes upfront capital costs, fixed and variable O&M costs,
fuel costs, and carbon tax. We then subtract the lifetime energy revenues from the gross
lifetime costs to arrive at the net capacity cost for the asset.
Energy storage is not a generation asset, and to estimate a proxy net capacity cost for
LDES, we assume that the round-trip energy losses are captured as fuel costs.
The net capacity cost of all fossil fuel-based resources increases marginally due to theincrease in carbon tax and natural gas prices, while the net capacity cost of LDES will continue
to drop. Thus, over the next decade, on a net capacity cost basis, LDES will continue to be a

Additional Details on the Methodology Net Capacity Calculation is provided in Appendix B
This does not include the incremental cost of a generation resource. However, the LDES is assumed to be
charged from the grid at a prevailing marginal price of $75/MWh.
16
The calculations do not include the impacts of the Investment Tax Credit.
14
15

Energy + Climate Advisorsbuildings ∙ mobility ∙ industry ∙ energy7more economical capacity option compared to natural gas combined cycle17 and gas
peakers18.
The net capacity cost of peaker plants powered by green hydrogen19 falls significantly due tothe dropping costs of renewable generation and electrolyzers. This analysis assumes thatgreen hydrogen is produced from a dedicated onshore wind asset coupled with a battery
storage facility in Ontario. However, it remains the most expensive capacity option among theassessed technologies20. The net capacity costs for SMRs decrease marginally; however, if SMRs
are deployed at the pace and magnitude as envisioned in the P2D, the net capacity costs
could be comparable to LDES.
Therefore, from a cost perspective, LDES could be a more cost-effective capacity option
even without consideration of the Investment Tax Credit. The 30% Federal Investment Tax
Credit available to LDES technologies until 2033 would further improve cost-effectiveness.

Assumes a natural gas combustion turbine with carbon storage. Upfront capital and O&M costs were obtained
from EIA's Annual Energy Outlook. Carbon taxes and prices are included, assuming carbon prices will increase
from $65/ton to $170/ton by 2032 and remain steady thereafter. Assumes an 85% capture rate, and the carbon
taxes were assumed to apply to only 15% of the theoretical emissions from similar natural gas combined cycle
facilities. The heat rate was assumed to be 12,000 BTU/kWh for the combined cycle with carbon storage.
18
The Expedited Long-Term Request for Proposal (RFP) has stated a Fixed Capacity Payment of $1093 per MWbusiness day for natural gas facilities. On a 250-day basis, this translates to a capacity value of $273 per kW-year.
As a result, the estimated net capacity costs for natural gas peakers in the analysis are approximately 60% lower
than the most recent E-LT1 RFP results.
19
The battery storage balances the variability of wind generation to increase the utilization of the electrolyzer,
which is sized to the average capacity factor of onshore wind. The cost of storing and transporting hydrogen byrail is factored into the calculation. Additionally, the cost and performance of hydrogen turbines are assumed tobe similar to that of natural gas peakers.
20
Due to the technical and safety challenges of transporting hydrogen through pipelines, the net capacity costs ofblue hydrogen were not considered in this analysis. The production costs of blue hydrogen are lower than thoseof green hydrogen. However, the delivery cost through a pipeline from Alberta adds about $3.5/kg, making bluehydrogen comparable if not more expensive than locally produced green hydrogen in Ontario.
https://doi.org/10.1016/j.ijhydene.2021.12.025
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83. The Need for LDES
3.1 Ontario’s Net Zero Pathways
Several net-zero pathway studies have explored how Ontario can decarbonize its building,transportation, and industrial sectors to achieve net zero by 2050. To power these sectors,
there is consensus that the electricity system’s demand will increase by 2 to 3 times current
levels by 2050. Despite that directional alignment, the different pathways differ in terms of theexact magnitude of demand growth as well as the range of solutions that are deemed leastcost and best fit for meeting the emerging system needs.
IESO’s Pathways to Decarbonization21 (P2D) evaluates two scenarios – a moratorium on new
natural gas generation by 2035 and a pathway to a decarbonized electricity system by 2050.
The latter scenario relies on significant large nuclear, SMR deployment and hydrogenturbines while not considering LDES in any significant way.
By 2050, P2D adds 68,800 MW of new capacity to reach a total system capacity of 88,400
MW. This includes a much wider generation mix, with new nuclear, wind, and hydrogenturbines accounting for over a quarter of the installed capacity each, while solar, demand
response, imports from Quebec, energy storage, and hydroelectric power account for theremaining capacity.
The P2D report identifies several caveats, including the current moratorium on offshore wind,
the risks of relying on hydrogen imports, and the uncertainty of imports from Quebec, given
winter capacity constraints. Additionally, for SMRs, the study recognizes that long lead times,
supply chain risks, and uncertain technological readiness (TRL 6) are key risks and could delay
deployment.
THE COMPLIMENTARY ROLE OF SHORT AND LONG-DURATION ENERGY STORAGE
The role of long-duration energy storage (LDES) is multifaceted and plays a crucial role inaddressing emerging reliability needs. While 4-hour lithium-ion systems excel in
responding to short-term demand fluctuations, LDES meets the challenges associated withlonger summer and winter peaks, integration of higher levels of renewable energy (RE) or
nuclear energy, greater grid reliability and T&D infrastructure deferral.
It is essential to acknowledge that 4-hour and longer-duration storage systems have distinct
roles within the energy storage portfolio. The 4-hour lithium-ion systems are well-suited for
addressing immediate grid demands such as peaking reliability needs and capacity
shortfalls. Numerous studies, including the P2D and other related analyses, haverecognized and emphasized the critical role of short-term storage in ensuring grid stability
and reliability.
However, as the energy landscape evolves and the penetration of renewable energy
sources continues to grow, the incremental value of LDES becomes evident. Longerduration storage systems are uniquely positioned to support the integration of higher

21

Pathways-to-Decarbonization

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9levels of renewable energy by providing sustained power output during extended periodsof low renewable generation, such as winter peaks or lulls in solar and wind resources.
This study predominantly focuses on the significance of longer-duration storage insupporting the integration of clean electricity through additional nuclear and renewableenergy capacity, increasing system reliability, and addressing emerging system needs.
Doing so aims to add an additional layer of analysis regarding the critical need for abalanced energy storage portfolio to meet Ontario’s emerging system needs. While 4-hourstorage systems will be important in addressing peak needs, longer-duration storage
emerges as a key enabler for the continued evolution and optimization of the energy
storage landscape.

3.2 LDES in Net Zero Pathways Studies
To date, most net-zero pathway studies have been fairly limited in the scope and depth of
consideration of LDES technologies. For example, the P2D study was primarily focused on
short-term battery storage technologies, with minimal consideration of LDES. The IESO
recognizes other technologies could play a role, but it does not consider other LDES
technology options beyond hydrogen turbines to meet capacity and peaking needs.
In addition to looking at the IESO’s P2D study, we reviewed four major national pathways
studies for their treatment of LDES. These four studies represent some of Canada's mostcomprehensive decarbonization studies.
•

•

•
•

Canada’s Energy Future 2023 (EF2023) from the Canadian Energy Regulator: The
EF2023 report only evaluates storage generally based on the potential for energy
arbitrage and acknowledges that this is a limitation in the modelling. It indicates thatthe storage selected by the model was “only battery storage.” However, with noevaluation of capacity or the other contributions to reliability provided by storage,
including LDES, this cannot be seen as a reasonable evaluation of the potential for
LDES in decarbonization.
Canadian Energy Outlook 2021 – Horizon 2060 (IET2021) from the Institut del’énergie Trottier: This was the only study that gives any detail on LDES and provides atable giving the price assumptions for a range of LDES technologies. However, thereport gives energy storage results in general terms, not specifying between longduration and short-duration storage.
Canadian National Electrification Assessment (CNEA) from the Electric Power
Research Institute: The study does not specify the types of storage selected. However,it states, “most of the capacity is battery storage.”North American Renewable Integration Study: A Canadian Perspective (NARIS)
from the National Renewable Energy Lab of the US Department of Energy – This study
only considered four-hour lithium-ion batteries as a storage technology.

While all the studies – including the P2D - illustrate the underlying conditions that
demonstrate substantial needs for the services provided by LDES, overall, they do notprovide a comprehensive evaluation of LDES technologies and the role they can play,
only acknowledging that there may be a role for LDES or highlighting that otherresources could be a proxy for LDES.

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10Future decarbonization studies should improve the approach to evaluating LDES
technologies (as described in the call-out box below22). While the above studies haveexamined broad trends and contributed to our understanding of the texture ofdecarbonization solutions, improving on those results now requires better focus andprecision, including a more judicious approach to assessing storage. At a minimum, future
pathways studies should include the following improvements.
•
•

•
•

A robust evaluation of different LDES technologies in addition to short-duration storage.
Clear delineation and reasonable assumptions regarding the reliability needs forplanning and grid support, as well as the potential contribution of storage to meet thoseneeds.
An evaluation of how different storage durations can contribute to reliability and gridsupport.
Limits on deploying generating technologies and transmission that reflect realistic andattainable ramping of the construction and capital requirements.
Need for Evolved Energy Models: Grid planning is a complex process that requires
careful consideration of different factors. In the past, planners only modelled a few
representative days of the year to simplify the process. This streamlining was reasonable
when the grid was dominated by fossil-fueled power plants that could adjust their output
when reality diverged from the model. However, this approach is no longer suitable for adecarbonized grid, which relies heavily on renewable energy sources like wind and solar.
The production of these resources can vary significantly, which means that the energy
needed on one day might have been generated on another day or season that was notpart of the simplified model. To address this issue, a more comprehensive modelling
approach must be used to look at all hours of the year. By doing so, it becomes easier
to identify when there will be production surpluses and deficits and use LDES to reconcile
them.
CASE STUDY: The California Public Utilities Commission prepares a reference resource
plan every two years, which helps guide utility planning processes. It uses two models forthis purpose. The first model determines what new resources are needed to meet futureenergy needs, while the second model analyzes how the resource portfolio performs overthe entire year to ensure that all needs are met. Initially, the CPUC did not select any LDES
resources when it ran the first model. During an extensive public process, the commission
identified weaknesses in its models and made the necessary changes. After running thetwo models, the commission determined that nearly 1 GW of LDES resources will benecessary by 2026 to meet the projected capacity needs in California.

Jeremy Twitchell (2023) Laying the groundwork for long-duration energy storage, Bulletin of the Atomic
Scientists, 79:6, 372-376, DOI: 10.1080/00963402.2023.2266939
22

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113.3 Risks in Pathways to Net ZeroThe proposed pathways to net zero explore different technology solutions to help Ontario
reduce its reliance on natural gas and ensure reliability. However, each pathway carries
inherent supply, planning, and deployment risks. If these risks materialize, there will be asignificant capacity shortfall that will not only diminish efforts to achieve net zero but also
have a significant impact on the affordability, safety and reliability of Ontario’s electricity
system. We will explore the potential contributions and role of LDES in mitigating the risks ineach scenario.
For the purpose of this analysis, we focus on the IESO’s P2D study, as it represents themost robust vision put forward to date by the system operator. As seen in Figure 2, under
the P2D study, the build-out of SMRs and hydrogen turbines is critical in ensuring system
reliability and successfully meeting Ontario’s 2050 electricity demand.

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Figure 2: Ontario's System Supply and Demand under P2D 23

We identify three key potential risks to the pathway laid out in the P2D that could impact thetransition to a net-zero electricity system. These risks are explored in the next sub-sections.

Build-out Risk
Small Modular Reactors (SMRs) are rapidly approaching technical maturity by integrating
established nuclear technology principles, innovative design features, advanced safetymeasures, and successful testing and validation. They are purported to be more cost-effective
compared to traditional nuclear power generation by using off-site, standardized
manufacturing and modular construction. There is a high potential for widespread economies
of scale to rapidly bring down costs and construction lead times for SMRs. However, despite

23

Others include hydroelectric, wind, solar, bioenergy, demand response and dispatchable load.

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12ambitious plans to deploy a large capacity of SMRs over the coming decades, global
deployment has been limited. As a result, there is limited real-world experience on the cost ofbuilding and operating such projects. 24
The economies of scale for SMRs depend on design convergence and effective supply
chains. With dozens of potential designs proposed globally, only a handful will becompetitive in the long-term – Ontario has endorsed the General Electric - Hitachi design, but
this will be first-of-its-kind. There is substantial potential for Canada to drive the supply chain
development for these reactors, and Ontario can benefit immensely from this, but the
timeline for developing these supply chains is still uncertain.25
SMRs still face regulatory and permitting challenges despite the relative inherent safetycompared to traditional nuclear because of their passive cooling systems. Regulatory
authorities have processes to evaluate traditional reactors and must adapt their regulatory
and permitting processes – with many jurisdictions intending to deploy SMRs – but effective
deployment depends on proven economies of scale. Regulatory and permitting delays across
many authorities will have compounding effects, slowing global deployment.
Ontario has accepted the environmental assessment of the Darlington SMR, but the Canadian
Nuclear Safety Commission has never licensed a reactor that is not a CANDU design.26
Further global SMR deployment will depend on policy and regulatory support to secure
private sector investment. The sizable opportunity for SMRs will depend on the speed of
deployment in the coming years, which relies on the timely navigation of regulatory andpermitting requirements27.
➔ Takeaway: There is a significant risk that SMR projects may not be deployed at
the pace or magnitude envisioned in P2D due to regulatory delays, supply chain
issues and other global deployment/technology developments.

IEA, Nuclear Power and Secure Energy Transitions.
Government of Ontario, A Strategic Plan for the Deployment of Small Modular Reactors
26
OPG, Bruce Power, NB Power, and SaskPower: Feasibility of Small Modular Reactor Development and
Deployment in Canada (2021)
27
Energy Storage Canada is supportive and acknowledges the role that SMRs would play in meeting Ontario’s
capacity and reliability constraints.
24
25

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13Hydrogen Supply Risk
The P2D uses Hydrogen-powered turbines as an effective proxy for a wider range of gas
peaker replacement options. However, this vision is primarily based on an abundance of lowcost blue H2, likely to be transported from Western Canada to Ontario through dedicatedpipelines. As noted in a Techno-Economic analysis of Hydrogen Pipelines by the Transition
Accelerator28, the operations of hydrogen pipelines are challenging for various reasons.
Firstly, the design, construction, and operation of hydrogen pipelines are more complex thanpipelines that transport other gases and liquids because hydrogen has a low density. Second,hydrogen pipelines are prone to embrittlement. Lower-strength steel and polyethylene
pipelines are less susceptible to hydrogen attack and embrittlement than high-pressure, highcarbon steel. Therefore, hydrogen is a more viable option for small distribution pipelines thanlarge inter-provincial distribution. Furthermore, the safety risks associated with hydrogen are
greater than those with natural gas because hydrogen has a large flammability range in theair, requires a small amount of energy for ignition, and its flame is invisible.
If Ontario instead increases reliance on locally produced green or pink hydrogen, this willfurther increase provincial generation and transmission infrastructure expansion beyond
current procurement planning, potentially competing with transportation and industry sector
electricity demand for electrification, intensifying uncertainties for system transformation.
Producing 1kg of green hydrogen requires 50 kWh of renewable energy. Therefore, tosupport the operations of 15 GW of hydrogen turbines and provide winter reliability, we
would need to direct 66.5 TWh29 of renewable capacity to hydrogen production, increasing
Ontario's 2050 energy needs by 22%30.
This could exacerbate the current capacity constraints in Ontario and challenge the path tonet zero by 2050. While we don’t anticipate that the grid would be running electrolyzers to
produce green hydrogen while also using green hydrogen to generate electricity, adding thedemand to create green hydrogen to the system will result in more hours where the system iscloser to load resource balance. The additional demands on the electricity grid would create
spillover effects into times when demand is high enough to interrupt green hydrogenproduction. However, this possibility could be mitigated by producing green hydrogen at
non-grid connected facilities, using a combination of co-located renewable generation,energy storage, and power from the Ontario electric grid. Short and long-duration energy
storage could be leveraged to increase electrolyzer utilization and alleviate potential grid
capacity constraints.
There could be an opportunity for pink hydrogen to be produced through nuclear powerfrom both new and existing nuclear generation assets. This process has the potential to be amajor source of Ontario’s zero carbon hydrogen supply but has not as yet been deployed atscale. Moreover, like green hydrogen, pink hydrogen would require additional generation forelectrification to substitute for the nuclear power committed to electrolysis.

Transition Accelerator: The-Techno-Economics-of-Hydrogen-Pipelines
According to the P2D, 15 GW of hydrogen turbines would generate approximately 11.6 TWh of electricity with acapacity factor of around 9%. If Ontario pivoted towards green hydrogen, 5.7 GWh of clean electricity would beneeded to generate 1 GWh from hydrogen turbines. GE Whitepaper
30
Assumes that the P2D does not include the energy requirements to produce green hydrogen, because it
models low-carbon hydrogen as a theoretical compliance path.
28
29

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14➔ Takeaway: There is a significant risk of inadequate blue and green hydrogen
supply to power hydrogen turbines, which, if materialized, could result in 15 GW ofcapacity shortage by 2050.

Planning and Procurement Risk
Load Forecasting Risk

35
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Upward Revision ofPlanning Estimates

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Annual Wingter Demand Forecast (GW)As the pace of innovation and disruptions in the electricity sector has increased, system
planners face higher uncertainty around forecasted demand patterns, impacting forecasts'
accuracy and precision. The IESO’s Annual Planning Outlook (APO) forecasts the system’senergy demand for a 10-year period. An analysis of the past four revisions of the APO
provide insight into the changing system outlooks planners expect year-over-year, with eachconsecutive APO consistently showing a higher demand than the previous one. As seen in
Figure 3, in 2019, the APO indicated that the winter demand in Ontario would be around 23
GW by 2040; the most recent revisions to the APO have revised the projected demand to 30
GW.

APO 2022

Figure 3: Winter Peak Demand Forecasts by Annual Planning Outlook 2019 - 2022

Import Capacity Risks
Additionally, the Pathways to Decarbonization (P2D) strategy relies on imports, assuming that
3.8 GW of energy would be provided through Quebec. However, there is a risk of insufficientimport capacity from Quebec. Quebec already has major heating needs during the wintermonths, making it a winter-peaking region. In addition to its own energy production capacity
and long-term power purchase agreements (PPAs) with Independent Power Producers (IPPs),
Hydro-Quebec also depends on short-term PPAs and power purchases from Independent
Electricity System Operator (IESO), New York Independent System Operator (NY-ISO), andEnergy + Climate Advisorsbuildings ∙ mobility ∙ industry ∙ energy

15

ISO New England, as well as demand response programs, such as "interruptible" orresidential Demand Response. While interconnections exist between IESO and HydroQuebec's transmission grid, Quebec's winter capacity constraints could limit the imports thatare positioned in the P2D study. This is especially true because coincident peaks are likely ina P2D world wherein Ontario will shift to a winter peaking system.
Compounding uncertainties and potential coincident peaks is the fact that building
interprovincial transmission lines is a challenging task. These projects often require crossing
provincial and territorial boundaries, which means coordination among multiple regulatory
bodies. This can lead to delays and increased complexity due to different regulatory regimes.
The sheer scale of transmission projects, especially over long distances, can also result in
substantial construction costs. Allocating these costs fairly among provinces and stakeholders
can be a difficult negotiation process. Furthermore, even if the transmission networks arebuilt as planned, it is unclear how increasing energy demands across all jurisdictions, thetransition to winter-peaking regimes with widespread electrification, and extreme weather
patterns will affect the available export capacities from Ontario’s neighbouring provinces andstates.
Resource Recontracting Risk
Additionally, the APO 2022 modelled the scenario with no contract extension for legacy
assets. The scenario assumes contracts and commitments are not reacquired except forhydroelectric resources. As a result, the installed capacity decreases from 41 to 29 GW in thenext decade before levelling off at approximately 23 GW through 2043.31➔ Takeaway: Underestimation of future demand, constraints on imports anduncertainty around the re-commitment of assets could significantly impact system
reliability.
Role of LDES Meeting Capacity Shortfalls
The above analysis focuses on the potential for a gap in the IESO’s plan through delayed
deployment of new nuclear and hydrogen supply risks, uncertain planning, andprocurement risks. LDES is one of the solutions to address capacity shortfalls, and thisstudy aims to highlight the potential for LDES to mitigate some of the risks by reducing thetotal amount of shortfall possible. The evaluation assumes LDES would play a role infirming up variable generation resources such as wind and solar to meet capacity
shortfalls. Additionally, LDES and renewables could offset a portion of natural gas orbaseload generation. However, the degree to which LDES will reduce capacity shortfall
depends on the resources built and what has yet to be retired.

In its latest Resource Adequacy Update - Evaluating Procurement Options for Supply Adequacy, the IESO is
exploring designing its long-term procurements to enable the participation of existing and new wind and solar
facilities willing to repower.
31

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4. The Value Proposition
4.1 Modeled Scenarios
Based on the IESO’s Pathways to Decarbonization study, Ontario’s peak demand32 is expected
to grow from 23 GW today to 60 GW by 2050. The P2D anticipates adding 69 GWs ofcapacity by 2050 to meet this need. In this case, the analysis assumes that the contracts forthe current generation capacity are extended as per the 2022 APO until 2043 and will ramp
down linearly to 16.5 GW by 2050, as anticipated in the P2D study. Moreover, this assumes
the anticipated capacity buildout will be proportional to the expected capacity shortfall.
Figure 4 below shows that under this base case, assuming perfect foresight, Ontario will not
experience any capacity shortfall.

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Figure 4: Ontario's Capacity Needs until 205033

Building on the inherent risks in Ontario’s net-zero pathway discussed in a previous section,
we developed three illustrative scenarios that map out potential trajectories for Ontario
should the identified risks materialize. The scenarios are not forecasts of the future but
rather intended to serve purely as illustrative case studies of potential outcomes under theidentified risks.
•

32
33

Scenario 1 - Buildout Risk: Under this scenario, the deployment of new nuclear assets
and hydrogen turbines in Ontario is assumed to occur at a slower-than-expected pace ormagnitude (relative to that outlined in the P2D). This scenario assumes that only 60% of
the SMR capacity and 10% of the hydrogen capacity are deployed as envisioned in theP2D. This could result in a significant capacity shortage of 4 GW by 2035 and 19 GW in

Assumes winter peak demand, since Ontario is expected to switch to a winter peaking system by mid 2030.
Others include hydroelectric, wind, solar, bioenergy, demand response and dispatchable load.

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172050. In this hypothetical scenario, to maintain reliability, the IESO could contemplate
deploying new natural gas in the near term until 2035. At the same time, there could be afocus on a rapid expansion of wind and LDES to firm up variable renewable generationand provide the much-needed capacity.
•

Scenario 2 – Hydrogen Supply Risk: In this scenario, new nuclear assets are assumed to
be deployed at the pace and scale outlined in the P2D. However, the limited availability ofblue hydrogen supply (as envisioned in the P2D as a proxy for wider gas decarbonization)
results in limitations on the deployment of hydrogen-powered turbines. Ontario could
instead produce some green hydrogen, limiting impacts on peak demand so as not toexacerbate capacity needs, which could limit the deployment of green hydrogenpowered combustion turbines to 1.5 GW (10% of the anticipated capacity in the P2D) by
2050. This could result in a significant capacity shortage of 3 GW by 2035 and 13 GW in
2050. LDES plays a similar role in this scenario by firming wind to alleviate capacity
shortfalls.

•

Scenario 3 – Planning and Procurement Risk: Under this scenario, new nuclear assets
are assumed to be deployed at the pace and scale outlined in the P2D, and H2 turbine
deployment is assumed to be 50% of the capacity buildout as anticipated in the P2D. This
scenario captures the risk of capacity shortfall due to contracts expiring, higher-thanexpected peak demand or import constraints and assumes that only 50% of the import
capacity, as anticipated in the P2D, is realized. This could result in a significant near-term
capacity shortage of 12 GW by 2035 and 9 GW in 2050. In this case, LDES powered bywind still has a role in providing system reliability.
Modelling Approach: To assess the value of LDES in different scenarios, we first determine
the corresponding capacity, reliability, and regulation requirements. Then, we assign a grid
service value to each requirement. LDES assets are then assumed to operate according to apriority order, which is regulation, reserves, and generation capacity. The analysis assumes
that only a portion of the reserves and regulations are allocated to a specific technology.
Additional modelling details are presented in Appendix B.
The results of the analysis should be reviewed with consideration of the following caveats:
1. This analysis is a high-level examination of the key benefits LDES can provide by
mitigating potential supply, planning, and deployment risks. We did not use a
production cost model to determine potential savings. Instead, we estimate thepotential benefits from LDES based on an assumed avoidance of counterfactual
resources (e.g. natural gas, green hydrogen).
2. The scenarios presented are not intended to forecast the pace and magnitude of
the SMR and H2 build-out but rather to draw attention to the potential risk in thepathway to decarbonization. The purpose is to demonstrate potential capacity
shortfalls if risks materialize.
3. We understand that relying on LDES alone cannot substitute for a baseload
generation, such as SMRs. Therefore, Ontario should adopt a portfolio-based
approach that involves a combination of LDES, wind and nuclear power to addresspossible capacity shortfalls. Consequently, the IESO should incorporate LDES in its
system planning.
Further detailed analysis is required to establish appropriate LDES targets in Ontario.

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18

4.2 Key Results
Scenario 1: Build-out Risk

Capacity (GW)In this scenario, as seen below in Figure 5, about 10 GW (60%) of SMRs and 1.5 GW (10%) ofhydrogen turbines envisioned in the P2D will be deployed by 2050. Thus, if SMRs andHydrogen turbines are not deployed at the pace and magnitude necessary to support
reliability, the result is a capacity shortfall of 4 GW by 2035, which could grow to 19 GW by
2050.

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Figure 5: Ontario Capacity Outlook Under Scenario 1

In this scenario, we assume that LDES firmed by wind could offset some portion of thecapacity shortfall. However, it is unlikely that the capacity provided by LDES can fully
substitute the capacity generated by SMRs and other baseload power plants. After analyzingother studies and using professional judgment, as seen in Figure 6, we have assumed thatapproximately 24 GW LDES capacity could offset the expected shortfall of 19 GW in capacity
by 205034. After determining the technical potential of LDES to offset the capacity shortfall, we
iterated through different procurement capacities35 by 203236 to determine the cost-effective
amount of LDES necessary to maximize system benefits.

We assume that about 1.7 GW of LDES can offset about 1 GW of baseload generation. This is based on theanalysis conducted by Aurora Long Duration Energy Storage in Spain, which estimated that 15 GW of LDES could
replace 10 GW of natural gas CCGT. The IESO should conduct similar capacity expansion and production costmodelling exercises that could provide a capacity offset value for LDES that is more Ontario-specific. Sincehydrogen turbines are run at low-capacity factors (9%), we assume that LDES can replace H2 capacity on a one-toone basis.
35
While iterating through various procurement capacities, the capital and O&M costs per kW remained constantacross all system sizes. Only the amount of grid needs assigned to the project varied.
36
The year 2032 has been selected for procurement to maximize the benefits of the Investment Tax Credit (ITC). It
is anticipated that the ITC will decrease from 30% in 2033 to 15% in 2034. Any delays in procurement beyond
2032 would lead to an increase in project costs and a reduction in net benefits to the system.
34

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19Actual Capacity Shortfall

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Capacity (GW)30LDES Needed to Offset Capacity Shortfall

Figure 6: Technical Potential of LDES to Offset Capacity Shortfall as envisioned in Scenario 1

In Figure 7, the benefit-cost ratio for different levels of LDES deployment by 2032 is mappedfor scenario 1. Assuming a cost-effectiveness threshold of 1.137, up to 6 GW of 10-hr LDES
deployed by 2032 are estimated to be cost-effective under this scenario.
Cost-Effective

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Cost and Benefit ($B)

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Ratio

Figure 7: Benefit-Cost Ratios of LDES Deployment Levels by 2032

Thus, under scenario 1, the IESO should consider procurement of up to 6 GW of 10-hr LDES
to maximize system benefits and hedge against capacity shortfall. As seen in Figure 8, theA threshold of 1.1 benefit to cost ratio is used as the threshold for cost-effectiveness to provide a conservative
estimate in consideration of uncertainty in the analysis .
37

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20Lifetime Benefit - Costs ($Billion)

overall system benefits from 6 GW of 10-hr LDES38 deployed by 2032 would exceed the costs.
The largest driver of benefits is Generation Capacity39 (66% of overall benefits), followed bytransmission deferral40 (17%), Arbitrage41 (12% of overall benefits), and then reserves andregulation42 (4% of overall benefits). The costs are net of the investment tax credit43 andinclude operational costs44 and charging costs45 (assuming that LDES is charged by wind46).

$25
$20
$15

Transmission
Deferral, $3

Charging Costs, $1

Arbitrage, $2

Opex,$3

Transmission Deferral
Arbitrage
30 Min Reserve$10$5

10 Min Spinning Reserve
Generation
Capacity, $13

Net Capex,$14

Generation Capacity
Charging Costs
Opex
Net Capex$0

Benefit

Cost

Figure 8: Benefit-Cost Analysis of 6 GW LDES under Scenario 1 (In service 2032)

As shown in Figure 9, procuring up to 6 GW of 10-hour Long Duration Energy Storage(LDES), if deployed by 2032, could reduce the capacity shortfall until 2036. This will give IESO

Assumes a generic LDES technology with 10-hour discharge duration, with an RTE of 65%, an annual
degradation rate of 1% and a project life of 30 years. The analysis assumes that the LDES is cycled 130 times ayear.
39
The generation capacity needs were determined by the technical potential of the LDES, as described in Figure
6. It was assumed that the avoided generation capacity costs were based on the Net Cost of New Entry for a small
modular reactor from 2025 to 2050. If SMRs are delayed due to regulatory and permitting hurdles, then an LDES
would likely be compensated similarly to an SMR on a generation capacity cost basis.
40
The Transmission deferral avoided costs were obtained from the DER Study conducted by Dunsky for the IESO.
We assume that the portion of the LDES’s capacity allocated to generation also contributes to transmission
deferral.
41
The arbitrage values were determined using the difference between the average off-peak and average on-peak
avoided energy costs published by the IESO. The arbitrage potential assumes that LDES cycles 130 times a year,
and its arbitrage potential is capped at 60% of its energy capacity since it would typically reserve energy for
regulation and operating reserves.
42
Assumes that up to 10% of Ontario’s regulation and reserve requirements are allocated to LDES, and the LDES
system allocates capacity in the following order of priority: regulation, 10-min reserves, 30 reserves and finally, theremaining capacity is allocated to available generation capacity needs.
43
Assumes that 30% ITC is applied to upfront capital cost. Assumes that by 2032, the upfront cost of LDES will be
CA$3,300 per kW.
44. The operation and maintenance costs are assumed to be $32/kW-year.
45
Charging costs are the round-trip energy losses when charging from onshore wind.
46
Assumes that the cost of onshore wind in Ontario is $60/MWh in 2024, drops to $30/MWh by 2040, and remains
constant thereafter.
38

Energy + Climate Advisorsbuildings ∙ mobility ∙ industry ∙ energy

21Total Capacity (GW)

enough time to acquire additional energy and capacity resources to address future reliability
risks. A larger procurement of LDES could not only reduce capacity shortfalls but also provide
a significant runway for IESO to build out the capacity required to support Ontario's energy
and reliability needs.

14
12
10
8

Delays Risk of Capacity
Shortfall by 4 years

6
4

2
0

2032 2033 2034 2035 2036 2037 2038 2039 2040 2041 2042 2043 2044 2045
Updated Capacity Need Post LDESLDES Procurement

Original Capacity Shortfall

Figure 9: Impact of 6 GW LDES Procurement on Capacity Shortfall47

47

Based on high-level modeling, we assume that 6 GW of 10-hour LDES can offset up to 5 GW of firm capacity.

Energy + Climate Advisorsbuildings ∙ mobility ∙ industry ∙ energy

22

Scenario 2: Hydrogen Supply Risk

Capacity (GW)In this scenario, as seen below in Figure 10, our analysis assumes approximately 17 GW(100%) of SMRs and 1.5 GW (10%) of hydrogen turbines, as envisioned in the P2D, will be
deployed by 2050. Within this framework, if the risk of blue and green hydrogen supply
materializes and hydrogen turbines are not deployed at the pace and magnitude necessary
to support reliability, there could be a capacity shortfall of 3 GW by 2035, which could growto 13 GW by 2050.

80
70

13 GW

60

50
40
30
20
10

Existing Generation

OthersNew Batteries

New Nuclear

New Hydrogen

Capacity Need

2050

2049

2048

2047

2046

2045

2044

2043

2042

2041

2040

2039

2038

2037

2036

2035

2034

2033

2032

2031

2030

2029

2028

2027

2026

2025

0

New Imports

Figure 10: Ontario Capacity Outlook Under Scenario 2

In this scenario, we assume that LDES firmed by wind could offset some portion of thecapacity shortfall. Since hydrogen turbines are assumed to run at a low-capacity factor (9% as
in the P2D), for the purpose of simplicity, we assume that LDES can fully substitute thecapacity provided by hydrogen turbines. After analyzing other studies and using professional
judgment, as seen in Figure 11, we have projected that approximately 13 GW LDES capacity
could offset the expected shortfall of 13 GW in capacity by 205048.
After determining the technical potential of LDES capacity needed to offset the capacity
shortfall, we iterated through different procurement capacities49 by 203250 to determine theeconomic potential of LDES necessary to maximize system benefits.

We assume that about 1.7 GW of LDES can offset about 1 GW of baseload generation. This is based on theanalysis conducted by Aurora Long Duration Energy Storage in Spain, which estimated that 15 GW of LDES could
replace 10 GW of natural gas CCGT. The IESO should conduct similar capacity expansion and production costmodelling exercises that could provide a capacity offset value for LDES that is more Ontario-specific. Sincehydrogen turbines are run at low-capacity factors (9%), we assume that LDES can replace H2 capacity on a one-toone basis.
49
While iterating through various procurement capacities, the capital and O&M costs per kW remained constantacross all system sizes. Only the amount of grid needs assigned to the project varied.
50
The year 2032 has been selected for procurement to maximize the benefits of the Investment Tax Credit (ITC). It
is anticipated that the ITC will decrease from 30% in 2033 to 15% in 2034. Any delays in procurement beyond
2032 would lead to an increase in project costs and a reduction in net benefits to the system.
48

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23

Actual Capacity Shortfall

2050

2049

2048

2047

2046

2045

0

2044

0

2043

2

2042

2

2041

4

2040

4

2039

6

2038

6

2037

8

2036

8

2035

10

2034

10

2033

12

2032

12

2031

14

2030

Capacity (GW)14LDES Needed to Offset Capacity Shortfall

Figure 11: Technical Potential of LDES to Offset Capacity Shortfall as envisioned in Scenario 2

In Figure 712, the benefit-cost ratio for different levels of LDES deployment by 2032 ismapped for scenario 1. Assuming a cost-effectiveness threshold of 1.1, up to 10 GW of 10hr LDES deployed by 2032 are estimated to be cost-effective under this scenario.
Cost-Effective

1.50

$60

1.20

$45

0.90

$30

0.60

$15

0.30

$0

Benefit-Cost Ratio

Cost and Benefit ($B)

$75

0.00

2 GW

4 GW

6 GW

8 GW

10 GW

Total Cost

12 GW

Total Benefit

14 GW

16 GW

18 GW

Ratio

Figure 12: Benefit-Cost Ratios of LDES Deployment Levels by 2032

Thus, under scenario 2, the IESO should consider procurement of up to 10 GW of 10-hr LDES
to maximize system benefits and hedge against capacity shortfall. As seen in Figure 13, theEnergy + Climate Advisorsbuildings ∙ mobility ∙ industry ∙ energy

24Lifetime Benefit - Costs ($Billion)

overall system benefits from 10 GW of 10-hr LDES51 deployed by 2032 would exceed thecosts. The largest driver of benefits is Generation Capacity52 (68% of overall benefits),
followed by transmission deferral53 (13%), Arbitrage54 (13% of overall benefits), and reserves
and regulation55 (6% of overall benefits). The costs are net of the investment tax credit56 andinclude operational costs57 and charging costs58 (assuming that LDES is charged by wind59).
$35

$30

Transmission
Deferral, $4

Charging Costs, $2$25

Arbitrage, $4

Opex,$5

Transmission Deferral$20

Arbitrage
30 Min Reserve

$15
$10

Generation
Capacity, $22

Net Capex,$23$5

10 Min Spinning Reserve
Generation Capacity
Charging Costs
Opex
Net Capex$-

Benefit

Cost

Figure 13: Benefit-Cost Analysis of 10 GW LDES under Scenario 2 (In service 2032)

As shown in Figure 14, the procurement of up to 10 GW of 10-hour Long Duration Energy
Storage (LDES) deployed by 2032 could reduce the capacity shortfall until 2046. This could
give IESO enough time to acquire additional energy and capacity resources to address future

Assumes a generic LDES technology with 10-hour discharge duration, with an RTE of 65%, an annual
degradation rate of 1% and a project life of 30 years. The analysis assumes that the LDES is cycled 130 times ayear.
52
The generation capacity needs were determined by the technical potential of the LDES, as described in Figure
11. It was assumed that the avoided generation capacity costs were based on the Net Cost of New Entry for anatural gas peaker small modular reactor from 2025 to 2035 and a green hydrogen peaker from 2035 onwards.
53
The Transmission deferral avoided costs were obtained from the DER Study conducted by Dunsky for the IESO.
We assume that the portion of the LDES’s capacity allocated to generation also contributes to transmission
deferral.
54
The arbitrage values were determined using the difference between the average off-peak and average on-peak
avoided energy costs published by the IESO. The arbitrage potential assumes that LDES cycles 130 times a year,
and its arbitrage potential is capped at 60% of its energy capacity since it would typically reserve energy for
regulation and operating reserves.
55
Assumes that up to 10% of Ontario’s regulation and reserve requirements are allocated to LDES, and the LDES
system allocates capacity in the following order of priority: regulation, 10-min reserves, 30 reserves and finally, theremaining capacity is allocated to available generation capacity needs.
56
Assumes that 30% ITC is applied to upfront capital cost. Assumes that by 2032, the upfront cost of LDES will be
CA$3,300 per kW.
57. The operation and maintenance costs are assumed to be $32/kW-year.
58
Charging costs are the round-trip energy losses when charging from onshore wind.
59
Assumes that the cost of onshore wind in Ontario is $60/MWh in 2024, drops to $30/MWh by 2040, and remains
constant thereafter.
51

Energy + Climate Advisorsbuildings ∙ mobility ∙ industry ∙ energy

25reliability risks. A larger procurement of LDES could not only reduce capacity shortfalls but
also provide a significant runway for IESO to build out the capacity required to support
Ontario's energy and reliability needs.

Total Capacity (GW)

20
18
16
14

Delays Risk of Capacity
Shortfall by 15 years

12
10
8
6
4
2

Updated Capacity Need Post LDES
Original Capacity Shortfall

2050

2049

2048

2047

2046

2045

2044

2043

2042

2041

2040

2039

2038

2037

2036

2035

2034

2033

2032

0

LDES Procurement

Figure 14: Impact of 10 GW LDES Procurement on Capacity Shortfall

Energy + Climate Advisorsbuildings ∙ mobility ∙ industry ∙ energy

26

Scenario 3: Planning and Procurement Risk

Capacity (GW)

In scenario 3, as seen in Figure 15 below, about 17 GW (100%) of SMRs and 7.5 GW (50%) ofhydrogen turbines envisioned in the P2D are deployed by 2050. In this scenario, we assume
that Quebec's winter capacity constraints could limit the import capacity to Ontario by 50%.
Additionally, we assume that existing generation assets are not recommitted, which results ina significant near-term capacity shortfall of 12 GW by 2035 and 9 GW by 2050.

80
70

9 GW

60

50
40
30
20
10

Existing Generation

OthersNew Batteries

New Nuclear

New Hydrogen

Capacity Need

2050

2049

2048

2047

2046

2045

2044

2043

2042

2041

2040

2039

2038

2037

2036

2035

2034

2033

2032

2031

2030

2029

2028

2027

2026

2025

0

New Imports

Figure 15: Ontario Capacity Outlook Under Scenario 3This scenario assumes that LDES, firmed by wind, could offset some portion of the capacity
shortfall. Since hydrogen turbines are assumed to run at a low capacity factor (9% as in theP2D), for simplicity purposes, we conclude that LDES can fully substitute the capacity
provided by hydrogen turbines and the expected capacity from imports.
As illustrated in Figure 16, we determined the technical capacity potential for LDES for eachyear from 2030 to 2050.60 We then modelled various LDES capacities61 procured by 203262 todetermine the amount of LDES that is cost-effective.

We assume that about 1.7 GW of LDES can offset about 1 GW of baseload generation. This is based on theanalysis conducted by Aurora Long Duration Energy Storage in Spain, which estimated that 15 GW of LDES could
replace 10 GW of natural gas CCGT. The IESO should conduct similar capacity expansion and production costmodelling exercises that could provide a capacity offset value for LDES that is more Ontario-specific. Sincehydrogen turbines are run at low-capacity factors (9%), we assume that LDES can replace H2 capacity on a one-toone basis.
61
While iterating through various procurement capacities, the capital and O&M costs per kW remained constantacross all system sizes. Only the amount of grid needs assigned to the project varied.
62
The year 2032 has been selected for procurement to maximize the benefits of the Investment Tax Credit (ITC). It
is anticipated that the ITC will decrease from 30% in 2033 to 15% in 2034. Any delays in procurement beyond
2032 would lead to an increase in project costs and a reduction in net benefits to the system.
60

Energy + Climate Advisorsbuildings ∙ mobility ∙ industry ∙ energy27

Actual Capacity Shortfall

2050

2049

2048

2047

0

2046

2

0

2045

2

2044

4

2043

4

2042

6

2041

8

6

2040

8

2039

10

2038

12

10

2037

12

2036

14

2035

14

2034

16

2033

18

16

2032

18

2031

20

2030

Capacity (GW)20LDES Needed to Offset Capacity Shortfall

Figure 16: Technical Potential of LDES to Offset Capacity Shortfall as envisioned in Scenario 3

In Figure 7, the benefit-cost ratio for different levels of LDES deployment by 2032 is mappedfor scenario 3. Assuming a cost-effectiveness threshold of 1.1, up to 18 GW of 10-hr LDES
deployed by 2032 are estimated to be cost-effective under this scenario.
Cost Effective

Cost and Benefit ($B)

$90

2.00
1.80

$80

1.60

$70

1.40

$60

1.20

$50

1.00

$40

0.80

$30

0.60

$20

0.40

$10

0.20

$0

Benefit-Cost Ratio

$100

0.00
2 GW

4 GW

6 GW

8 GW

10 GW

Total Cost

12 GW

Total Benefit

14 GW

16 GW

18 GW

Ratio

Figure 17: Benefit-Cost Ratios of LDES Deployment Levels

As seen in Figure 17, the benefit-cost ratios are largely stable up to 10 GW and then begin to
decline thereafter. Thus, under scenario 3, the IESO should consider procurement of up to 10
GW of 10-hr LDES to maximize system benefits and hedge against capacity shortfall. As seeninEnergy + Climate Advisorsbuildings ∙ mobility ∙ industry ∙ energy28Lifetime Benefit - Costs ($Billion)

Benefit-Cost Ratio of 10 GW of LDES in Service by 2032
$45
$40
$35

$30

Transmission
Deferral, $6

Arbitrage, $4
Charging Costs, $2

Opex,$5

$25
$20
$15
$10

Transmission Deferral
Arbitrage
30 Min Reserve

Generation
Capacity, $29

10 Min Spinning Reserve

Net Capex,$23

Generation Capacity
Charging Costs
Opex

$5

Net Capex$-

Benefit

Cost

Figure 18, the overall system benefits from 10 GW63 of 10-hr LDES64 deployed by 2032 would
exceed the costs. The largest driver of benefits is Generation Capacity65 (71% of overall
benefits), followed by transmission deferral66 (15%), Arbitrage67 (10% of overall benefits), andreserves and regulation68 (4% of overall benefits). The costs are net of the investment tax
credit69 and include operational costs70 and charging costs71 (assuming that LDES is charged
by wind).

Under scenario 3, the benefit-cost ratios are the highest up to 10 GW of LDES capacity.
Assumes a generic LDES technology with 10 10-hour discharge duration, with an RTE of 65%, an annual
degradation rate of 1% and a project life of 30 years. The analysis assumes that the LDES is cycled 130 times a
year.
65
The generation capacity needs were determined by the technical potential of the LDES, as described in Figure
16. It was assumed that the avoided generation capacity costs were based on the Net Cost of New Entry for anatural gas peaker small modular reactor from 2025 to 2035 and a green hydrogen peaker from 2035 onwards.
66
The Transmission deferral avoided costs were obtained from the DER Study conducted by Dunsky for the IESO.
We assume that the portion of the LDES’s capacity allocated to generation also contributes to transmission
deferral.
67
The arbitrage values were determined using the difference between the average off-peak and average on-peak
avoided energy costs published by the IESO. The arbitrage potential assumes that LDES cycles 130 times a year,
and its arbitrage potential is capped at 60% of its energy capacity since it would typically reserve energy for
regulation and operating reserves.
68
Assumes that up to 10% of Ontario’s regulation and reserve requirements are allocated to LDES, and the LDES
system allocates capacity in the following order of priority: regulation, 10-min reserves, 30 reserves and finally, theremaining capacity is allocated to available generation capacity needs.
69
Assumes that 30% ITC is applied to upfront capital cost. Assumes that by 2032, the upfront cost of LDES will be
CA$3,300 per kW.
70. The operation and maintenance costs are assumed to be $32/kW-year.
71
Charging costs are the round-trip energy losses when charging from onshore wind.
63
64

Energy + Climate Advisorsbuildings ∙ mobility ∙ industry ∙ energy29Lifetime Benefit - Costs ($Billion)

Benefit-Cost Ratio of 10 GW of LDES in Service by 2032
$45
$40
$35

$30

Transmission
Deferral, $6

Arbitrage, $4
Charging Costs, $2

Opex,$5

$25
$20
$15
$10

Transmission Deferral
Arbitrage
30 Min Reserve

Generation
Capacity, $29

10 Min Spinning Reserve

Net Capex,$23

Generation Capacity
Charging Costs
Opex

$5

Net Capex$-

Benefit

Cost

Figure 18: Benefit-Cost Analysis of 6 GW LDES under Scenario 3 (In service 2032)

Energy + Climate Advisorsbuildings ∙ mobility ∙ industry ∙ energy

30

4.3 Key Takeaways
LDES provides multiple benefits, such as environmental sustainability, grid reliability, andeconomic development. As illustrated in Figure 19 below, based on our initial high-level
analysis, across all three scenarios, up to 6 GW of 10-hr LDES deployed starting in 2032
could be cost-effective in Ontario. This can increase to up to 10 and 18 GW underscenarios 2 and 3, respectively, if capacity shortfalls exacerbate further.

Benefit-Cost Ratio

Cost-Effective

Scenario 3

10 GW
6 GW

Cost- Effectivenessthreshold

18 GW

Not Cost Effective
2 GW

4 GW

6 GW

8 GW

10 GW

12 GW

14 GW

16 GW

Scenario 1
Scenario 2

18 GW

Magnitude of LDES Deployment by 2032
Figure 19: Range of LDES procurement in Ontario

As seen in Figure 20 below, when we analyze LDES with a range of technology characteristics,
6 GW of 10-hr LDES could be cost-effective across the three scenarios.

$30.0

Benefit/ Cost ($B)

$25.0
$20.0

Range of 6 GW
LDES Costs

$15.0
$10.0
$5.0
$0.0

Scenario 1: Buildout Risk Scenario 2: H2 Supply Scenario 3: Planning and
Risk
Procurement Risk
Generation Capacity
30 Min Reserve

Regulation
Arbitrage

10 Min Spinning Reserve
Transmission Deferral

Figure 20: Range of LDES Costs Across Scenarios72

72

See Appendix B for detailed assumptions.

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31

The estimated upfront investment for the deployment of 6 GWs of LDES would besomewhere between $12B to $17B73, which represents only 3-5% of the total investments
expected in the P2D74. Additionally, based on our high-level assessment, the lifetime cost of
LDES could be significantly lower than that of equivalent hydrogen peakers. On a head-tohead basis, LDES75 powered by wind would cost up to 40% cheaper than blue76 hydrogen
peakers.
Based on our high-level analysis, commissioning 6 GW of LDES by 2032 could provide
savings of around $11B to $20B compared to the IESO's baseline P2D scenario. Thesesavings represent the difference in the lifetime cost of operating a 6 GW LDES powered bywind versus a green/blue hydrogen turbine of a similar capacity. Further detailed analysis isrequired to validate these estimates77.

LIfetime Costs (CA$B)

$60
$50
$40
$30

$20
$10
$0

Blue Hydrogen PeakerUpfront CostLDES
O&M Costs

Fuel Costs

Figure 21: Lifetime Costs of 6 GW of LDES and Hydrogen Peaker by 2032 (2024 CA$B)

Includes 30% ITC
The P2D anticipates that an investment in the range of $375 to $425 billion will be required for a bulk system
decarbonization.
75
Assumes the upfront cost of LDES is $4000 per kW by 2032. Assumes that LDES is charged from low-costonshore wind, which is assumed to be $60 per MWh over the life of the asset. The assumed lifetime is 25 years,
and it runs at a capacity factor of 10%.
76
Includes the final delivered price of blue hydrogen from Alberta to Ontario City Gate from an 85% SteamMethane Reformation CCS. https://doi.org/10.1016/j.ijhydene.2021.12.025 The assumed cost of blue hydrogen is$55/MMBTU by 2032. Upfront capital ($1460/kW) and O&M costs are assumed to be similar to those of natural
gas peakers. The fuel cost in the IESO P2D is assumed to be US$41/MMBTU, which is about CA$55/MMBTU. The
assumed lifetime is 25 years and runs at a capacity factor of 10%. This graph does not include a carbon tax.
77
To accurately determine the operational system-wide savings, running a production cost model with LDES isnecessary. Operational constraints might limit the capabilities of LDES and thus lead to lower system-wide savings.
Therefore, we recommend that the IESO incorporate LDES within their production cost models to determine thesystem-wide savings.
73
74

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32

4.4 Additional Benefits
System Benefits:•

Diversity of Supply: Ontario's energy needs could be met through a balanced mix ofenergy generation technologies, complemented by long-duration energy storage toensure capacity and reliability.

•

Reduced Wind Curtailment: LDES enables better integration of intermittent
renewable sources like wind power by storing excess energy during windy periods
and discharging it during lulls, reducing the need to curtail wind power production.

•

Reduced Nuclear Maneuvering: LDES relieves the need for nuclear assets to reduce
their output in the event of surplus system supply. LDES could allow nuclear assets tooperate at optimal levels regardless of system conditions, thereby improving longevity
and lifetime performance.

•

Offset Natural Gas Generation: LDES allows for the storage of excess renewableenergy during periods of low demand, reducing reliance on natural gas generation
during peak demand. This shift contributes to a significant reduction in greenhousegas emissions, aligning with Ontario’s Net Zero Goals.

•

Inertia: LDES systems can enhance grid stability by providing inertia, helping tomaintain a consistent frequency. This is especially crucial in a system with a highpenetration of renewable energy sources, which may lack the inherent inertia
traditionally provided by fossil fuel generators.

•

Thermal Energy: Thermal-based long-duration energy storage technologies have theability to store and release thermal energy and make these resources suitable for
integrating with industrial processes that require heat. This opens opportunities forusing stored energy in various industrial applications, further diversifying its use cases.

Economic Benefits:•

Made in Ontario Development: Investing in and procuring LDES technologies
locally fosters the development of a domestic industry. This not only strengthens theresilience of the energy supply chain but also promotes technological innovation andexpertise within the province.

•

Economic Benefits (Jobs, GDP): The growth of the LDES sector has a multiplier effecton the economy. Beyond direct employment, it stimulates related industries andservices, increasing economic activity, higher GDP, and a more robust and diversified
economy.

Energy + Climate Advisorsbuildings ∙ mobility ∙ industry ∙ energy

33

Need for greater than 12-hour energy storage: This report analyzed the value
proposition of 10-hour LDES technology; however, energy storage for 12 hours or more
could be critical to achieving economy-wide decarbonization and high levels of renewableenergy penetration. Energy storage for 12 hours is considered diurnal and can time-shiftsolar and wind generation to periods of higher demand.
Ontario intends to rely heavily on solar (6,000 MW) and wind (17,600 MW), which isroughly a third of new installed capacity by 2050, from the Pathways to Decarbonization
study from the IESO, so addressing the mismatch in supply and demand with 12+ hourstorage could be critical.
Another key benefit is the potential for deferred or avoided transmission system upgradesby installing storage downstream from high-capacity transmission nodes – in this case,storage capacity installed to mitigate this would not need to see significant dischargefrequency since simply preventing overloading during a few peak events in a year could
provide the benefit to the system of preventing costly transmission system upgrades.
Mechanical LDES technologies, like pumped hydro and compressed air, have thepotential to meet this need, as well as grid-scale thermal energy storage.

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34

5. Recommendations
PLAN
1. Incorporate LDES in all future planning: Our high-level analysis suggests that across all
scenarios, there is up to 6 GW of cost-effective LDES potential in Ontario. Further analysis
and explorations are required by the IESO to validate the potential and corresponding
benefits. We recommend that the IESO conduct a more detailed analysis that considers afull array of LDES technologies in future planning with consideration of the potential
benefits to the grid, such as resource adequacy, operating reserves, regulations
compliance, and emission reduction.

2. Avoid locking in short-term procurements that undermine net zero efforts: Prioritize
solutions that align with long-term net-zero emission goals and avoid locking in technologythat may hinder decarbonization. Select technologies that address immediate needs
without crowding out the potential for decarbonized solutions.

PROCURE1. Adopt a multi-year procurement strategy with competitive auctions: The IESO should
consider multi-year procurement plans for LDES that provide certainty to developers andensure competitiveness. A clear roadmap and competitive auctions can encourage marketdriven solutions and achieve the best value for the grid and consumers.
2. Establish clear targets for LDES Deployment: Based on outcomes from its analysis, IESO
should define and communicate specific targets for deploying LDES in Ontario. This could
provide a roadmap for the necessary scale of implementation, foster investor confidence,
encourage strategic planning, and facilitate integration into the energy infrastructure.

3. Prioritize early procurements to capitalize on competitive pricing, leverage federal
funding, and address potential risks: Starting the procurement process early allows
for more competitive pricing and takes advantage of incentives such as the Investment
Tax Credit (ITC). Early procurements will also be critical to mitigate the challenges ofabbreviated procurement lead times, the prospect of first-of-a-kind permitting processes
and the longer lead times required for many LDES technologies.

PREPARE
1. Build confidence in the capabilities of LDES: Establish a dedicated funding stream fortesting and demonstration of innovative LDES technologies in the province.
2. Secure buy-in from municipalities and federal entities: The IESO must collaborate withmunicipal and federal entities for successful LDES projects. This could help address
regulatory and permitting challenges.

3. Strategic site selection to maximize value: IESO should analyze strategic sites for LDES
installations, considering factors like proximity to renewable energy sources, local
transmission needs, and relevant infrastructure. Strategically placing LDES projects canmaximize their value, optimize grid integration, minimize transmission losses, and enhancesystem efficiency.

Energy + Climate Advisorsbuildings ∙ mobility ∙ industry ∙ energy

35Appendix A: LDES Technology
A.1 LDES Technical Characteristics78
Table 1: Readiness of LDES Technologies

MarketReadinessMax
Deployment
(MW)

Max
NominalDuration(Hrs)

Average
RTE (%)

10-100

0-15

50-80

200-500

6-24

40-70

10-10025-100

20-50

>100

25-50

55-75

Gravity-based

20-1000

0-15

70-90

Liquid CO2

10-500

2-24

70-80

50-100

10-25

40-70

10-10025-10040-80

10-500200

55-90

10-10050-20040-70Technology

Commercial

Pumped hydro(PSH)

Pilot/
Demonstration
R&D
Stage

MechanicalCompressed air(CAES)
Latent heat(aluminum alloy)
Hybrid flow battery, liquid
electrolyte & metal anode

78

LDES
Category

ThermalElectrochem.

Liquid air(LAES)
Aqueous electrolyte flow
batteries
Sensible heat (e.g.,molten salts, rockmaterial, concrete)
Metal anode batteriesThis is an illustrative list of key LDES technologies, but not exhaustive list of LDES technology options.

Energy + Climate Advisorsbuildings ∙ mobility ∙ industry ∙ energy

A-1

Appendix B: Analytical Approach
To determine the total benefit of long-duration energy storage under various scenarios, we first establish the grid needs (capacity,reliability, and regulation) and then allocate a grid service value to each need.

B.1 Modelling Caveats•

The scenarios presented are not intended to forecast the pace and magnitude of the SMR and H2 build-out but rather todraw attention to the potential risk in the pathway to decarbonization. The purpose is to demonstrate that if those risksmaterialize, then LDES could have a role to play in addressing Ontario's capacity shortfalls.

•

We understand that relying on LDES alone cannot substitute for a baseload generation, such as SMRs. Therefore, Ontario
should adopt a portfolio-based approach that involves a combination of LDES, wind and nuclear power to addresspossible capacity shortfalls. Consequently, the IESO should incorporate LDES in its system planning.

•

We did not run a production cost model to determine the potential savings. The estimate of $11 billion to $20 billion isbased on the difference between substituting hydrogen turbines powered by blue hydrogen from Alberta with LDES.

B.2 Grid Needs Assessment
After analyzing IESO’s Pathways to Decarbonization and the IESO’s 2022 Annual Planning Outlook, we determined the anticipatedcapacity buildout necessary to maintain reliability79. First, we determined the capacity shortfall using the winter peak demand
from the P2D and leveraging the APO generation capacity forecast. Then, we determined the capacity shortfall in each year andassumed that the new capacity80 in the P2D would be deployed proportional to the capacity shortfall.

79
80

2027

2028

2029

2030

2031

2032

2033

2034

2035

2036

2037

2038

2039

2040

2041

2042

2043

2044

2045

2046

2047

2048

2049

2050

Total Winter
Demand (GW)
Existing Generation(APO Case 2)

2026

Capacity Build Out

2025

Table 2: Assumed Capacity Buildout in P2D

26

27

26

27

29

30

32

34

37

39

42

44

46

49

51

53

54

56

58

59

61

63

64

65

66

67

29

28

29

29

29

30

29

30

30

30

30

30

30

30

30

30

30

30

30

28

26

24

22

20

18

17

The P2D study does not provide an annual capacity buildout, instead it only provides the total new capacity build by 2050 and 2035.
Assumed effective capacity.

Energy + Climate Advisorsbuildings ∙ mobility ∙ industry ∙ energy

B-1

Capacity Build Out

2025

2026

2027

2028

2029

2030

2031

2032

2033

2034

2035

2036

2037

2038

2039

2040

2041

2042

2043

2044

2045

2046

2047

2048

2049

2050

New Nuclear

-

-

-

-

-

-

1

2

2

3

4

5

5

6

7

7

8

8

9

10

11

13

14

15

16

17

New H2

-

-

-

-

-

-

1

1

2

2

3

4

5

5

6

6

7

7

8

9

10

11

12

13

13

14

New Imports

-

-

-

-

-

-

-

-

1

1

1

1

1

1

2

2

2

2

2

2

3

3

3

3

4

4

New Batteries

-

-

-

-

-

-

-

-

-

-

-

1

1

1

1

1

1

1

1

1

1

1

2

2

2

2

New Others
Actual Capacity
Shortfall
Max LDES Neededto Offset Capacity

-

-

-

-

-

-

1

1

2

2

3

4

4

5

6

6

7

7

8

9

10

11

11

12

13

14

-

-

-

-

-

-

-

-

-

-

-

-

-

-

-

-

-

-

-

-

-

-

-

-

-

-

-

-

-

-

-

-

-

-

-

-

-

-

-

-

-

-

-

-

-

-

-

-

-

-

-

-

In each scenario, we assessed the impact on Ontario’s generation capacity if one or more risks materialize.
•

Scenario 1 – Build Out Risk: We assume that only 60% of the SMRs are deployed based on the P2D, and only 10% ofhydrogen turbines are deployed in Ontario due to supply challenges in delivering blue hydrogen through pipelines from
Alberta and increased restrictions on green hydrogen production in Ontario due to capacity constraints.
2025

2026

2027

2028

2029

2030

2031

2032

2033

2034

2035

2036

2037

2038

2039

2040

2041

2042

2043

2044

2045

2046

2047

2048

2049

2050

Table 3: Assumed Capacity Buildout in Scenario 1

26

27

26

27

29

30

32

34

37

39

42

44

46

49

51

53

54

56

58

59

61

63

64

65

66

67

29

28

29

29

29

30

29

30

30

30

30

30

30

30

30

30

30

30

30

28

26

24

22

20

18

17

-

-

-

-

-

-

1

1

1

2

2

3

3

4

4

4

5

5

5

6

7

8

8

9

9

10

New H2

-

-

-

-

-

-

-

-

-

-

-

-

-

1

1

1

1

1

1

1

1

1

1

1

1

1

New Imports

-

-

-

-

-

-

-

-

1

1

1

1

1

1

2

2

2

2

2

2

3

3

3

3

4

4

New Batteries

-

-

-

-

-

-

-

-

-

-

-

1

1

1

1

1

1

1

1

1

1

1

2

2

2

2

New Others
Actual Capacity
Shortfall

-

-

-

-

-

-

1

1

2

2

3

4

4

5

6

6

7

7

8

9

10

11

11

12

13

14

-

-

-

-

-

-

1

2

3

3

4

5

6

7

8

9

9

10

11

12

13

15

16

17

18

19

Capacity Build Out

Total Winter
Demand (GW)
Existing Generation(APO Case 2)
New Nuclear

Energy + Climate Advisorsbuildings ∙ mobility ∙ industry ∙ energy

B-2

Capacity Build Out

2025

2026

2027

2028

2029

2030

2031

2032

2033

2034

2035

2036

2037

2038

2039

2040

2041

2042

2043

2044

2045

2046

2047

2048

2049

2050

Max LDES Neededto Offset Capacity

-

-

-

-

-

-

2

2

3

4

5

7

8

9

10

11

11

12

13

15

16

18

20

21

23

24

•

Scenario 2 – H2 Supply Risks: We assume that 100% of the SMRs and 10% of the hydrogen turbines based on the P2D
are deployed in Ontario but are powered through green hydrogen from wind facilities in Ontario.
2025

2026

2027

2028

2029

2030

2031

2032

2033

2034

2035

2036

2037

2038

2039

2040

2041

2042

2043

2044

2045

2046

2047

2048

2049

2050

Table 4: Assumed Capacity Buildout in Scenario 2

26

27

26

27

29

30

32

34

37

39

42

44

46

49

51

53

54

56

58

59

61

63

64

65

66

67

29

28

29

29

29

30

29

30

30

30

30

30

30

30

30

30

30

30

30

28

26

24

22

20

18

17

-

-

-

-

-

-

1

2

2

3

4

5

5

6

7

7

8

8

9

10

11

13

14

15

16

17

New H2

-

-

-

-

-

-

-

-

-

-

-

-

-

1

1

1

1

1

1

1

1

1

1

1

1

1

New Imports

-

-

-

-

-

-

-

-

1

1

1

1

1

1

2

2

2

2

2

2

3

3

3

3

4

4

New Batteries

-

-

-

-

-

-

-

-

-

-

-

1

1

1

1

1

1

1

1

1

1

1

2

2

2

2

New Others
Actual Capacity
Shortfall
Max LDES Neededto Offset Capacity

-

-

-

-

-

-

1

1

2

2

3

4

4

5

6

6

7

7

8

9

10

11

11

12

13

14

-

-

-

-

-

-

1

1

2

2

3

3

4

5

5

6

6

7

7

8

9

10

10

11

12

13

-

-

-

-

-

-

1

1

2

2

3

4

4

5

5

6

6

7

7

8

9

10

11

11

12

13

Capacity Build Out

Total Winter
Demand (GW)
Existing Generation(APO Case 2)
New Nuclear•

Scenario 3 – Procurement Risks: Under this scenario, SMRs are assumed to be deployed at the pace and scale outlined in
the P2D, and H2 turbine deployment is assumed to be 50% of the capacity buildout as anticipated in the P2D. This
scenario captures the risk of capacity shortfall due to contracts expiring, higher-than-expected peak demand or importconstraints and assumes that only 50% of the import capacity, as anticipated in the P2D, is realized.

Capacity Build Out

2025

2026

2027

2028

2029

2030

2031

2032

2033

2034

2035

2036

2037

2038

2039

2040

2041

2042

2043

2044

2045

2046

2047

2048

2049

2050

Table 5: Assumed Capacity Buildout in Scenario 3

Total Winter
Demand (GW)

26

27

26

27

29

30

32

34

37

39

42

44

46

49

51

53

54

56

58

59

61

63

64

65

66

67

Energy + Climate Advisorsbuildings ∙ mobility ∙ industry ∙ energy

B-3

2025

2026

2027

2028

2029

2030

2031

2032

2033

2034

2035

2036

2037

2038

2039

2040

2041

2042

2043

2044

2045

2046

2047

2048

2049

2050

28

29

29

28

24

22

22

21

22

21

21

21

20

20

20

19

19

19

17

17

17

17

17

17

17

17

-

-

-

-

-

-

1

2

2

3

4

5

5

6

7

7

8

8

9

10

11

13

14

15

16

17

New H2

-

-

-

-

-

-

-

1

1

1

2

2

2

3

3

3

3

4

4

4

5

5

6

6

7

7.1

New Imports

-

-

-

-

-

-

-

-

-

-

-

1

1

1

1

1

1

1

1

1

1

1

2

2

2

2

New Batteries

-

-

-

-

-

-

-

-

-

-

-

1

1

1

1

1

1

1

1

1

1

1

2

2

2

2

New Others
Actual Capacity
Shortfall
Max LDES Neededto Offset Capacity

-

-

-

-

-

-

1

1

2

2

3

4

4

5

6

6

7

7

8

9

10

11

11

12

13

14

-

-

-

-

5

8

8

9

9

11

12

12

13

13

14

15

16

16

18

17

15

14

13

12

10

9

1

-

-

2

5

8

8

9

9

11

12

12

13

14

14

15

16

16

18

17

15

14

13

12

10

9

Capacity Build Out

Existing Generation(APO Case 1)
New Nuclear

Energy + Climate Advisorsbuildings ∙ mobility ∙ industry ∙ energy

B-4

25
20
15
10

Scenario 1: Buildout Risk

5

Scenario 2: H2 Supply Risk

0

Scenario 3: Planning and Procurement
Risk

2025
2026
2027
2028
2029
2030
2031
2032
2033
2034
2035
2036
2037
2038
2039
2040
2041
2042
2043
2044
2045
2046
2047
2048
2049
2050

Capacity Deficit Shortfall (GW)

Risk of Capacity Shortfall

Figure 22: Capacity Needs Assessment Under Various Scenarios

Once we have determined Ontario’s generation capacity needs, we will determine the regulation and operating reserve needs.
••

Reliability Needs: We assume Ontario’s spinning and operating reserve requirements are proportional to the peak demandand continue to grow as the peak demand81 grows. The reliability needs as a proportion of system peak demand is held
constant among the scenarios. We assume that the 10-minute reserve requirements will grow from 1,460 MW in 2025 to
3,760 MW by 2050, while the 30-minute reserve requirements will grow from 730 MW in 2025 to 1,880 MW by 2050.
Regulation: We assume Ontario’s regulation requirements are proportional to the peak demand and continue to grow as thepeak demand grows. We assume the regulation requirements will grow82 from 250 MW in 2025 to 650 MW by 2050.

The Grid Needs are assumed to be constant among the scenarios. In our modelling, we assume that 10% of the system’s 30minute operating reserve requirements are designated for the project. Additionally, 7% of the total 10-minute spinningrequirements are assigned to the LDES. When it comes to regulation, we assume that only 10% of the total regulation capacity isallocated to the LDES project.

81
82

Assumes 30-min spin is 2.8%- and 10-min spin at 5.6% of the system peak demand.
Assumes that regulation capacity is 1% of the total system peak demand.

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B-5

B.3 Grid Service Value
Generation Capacity Value: The value for generation capacity is based on the Net Cost of New Entry for the next marginal
resource. In this analysis, the Net CONE represents the annual revenues a new resource would need to earn, specifically in thecapacity market, after netting out energy. The Net CONE values are estimated for each year from 2025 to 2050 and are used as aproxy for generation capacity values.
•

Scenario 1 – Build Out Risk: Under this scenario, the generation capacity values are based on the Net CONE for small
modular reactors from 2025 to 2050.

•

Scenario 2 – H2 Supply Risks: Under this scenario, the generation capacity values are based on the Net CONE for anatural gas peaker from 2025 to 2035, after which the generation capacity values are based on the Net CONE for a greenhydrogen-powered gas peaker.

•

Scenario 3 – Procurement Risks: Similar to scenario 2, the generation capacity values are based on the Net CONE for anatural gas peaker from 2025 to 2035, after which the generation capacity values are based on the Net CONE for a greenhydrogen-powered gas peaker.

Capacity Value($/kW-yr)

2025

2026

2027

2028

2029

2030

2031

2032

2033

2034

2035

2040

2045

2050

Table 6: Generation Capacity Values ($/kW-yr) by Scenario

Scenario 1:
Buildout Risk

239

236

234

233

232

231

230

228

226

225

223

215

206

198

Scenario 2:
H2 Planning Risk

161

156

156

157

159

162

165

168

172

175

178

282

282

282

Scenario 3:
Procurement Risk

161

156

156

157

159

162

165

168

172

175

178

282

282

282

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B-6

Operating Reserve and Regulation Values: The 10-minute and 30-minute reserve and regulation serve values are assumed to
be proportionate based on the generation capacity values in each scenario. The 2025 reserve and regulation serve values weredeveloped based on the IESO’s forecast of prices and a scan of values in neighbouring jurisdictions.
Service Value($/kW-yr)

2025

2026

2027

2028

2029

2030

2031

2032

2033

2034

2035

2040

2045

2050

Table 7: Operating Reserve and Regulation Values ($/kW-yr) in Scenario 1

Regulation

$227

$224

$223

$222

$221

$220

$218

$217

$215

$214

$212

$204

$196

$188

30. in Spinning
Reserve

$209

$207

$205

$205

$204

$203

$201

$200

$198

$197

$196

$188

$181

$173

30 Min Reserve

$146

$145

$144

$143

$143

$142

$141

$140

$139

$138

$137

$132

$127

$121

Service Value($/kW-yr)

2025

2026

2027

2028

2029

2030

2031

2032

2033

2034

2035

2040

2045

2050

Table 8: Operating Reserve and Regulation Values ($/kW-yr) in Scenario 2

Regulation

$227

$220

$219

$221

$224

$228

$232

$237

$242

$247

$250

$397

$397

$397

10 Min Spinning
Reserve

$209

$202

$202

$204

$206

$210

$214

$218

$223

$227

$231

$366

$366

$366

30 Min Reserve

$146

$142

$141

$143

$144

$147

$150

$153

$156

$159

$161

$256

$256

$256

Service Value($/kW-yr)

2025

2026

2027

2028

2029

2030

2031

2032

2033

2034

2035

2040

2045

2050

Table 9: Operating Reserve and Regulation Values ($/kW-yr) in Scenario 3

Regulation

$227

$220

$219

$221

$224

$228

$232

$237

$242

$247

$250

$397

$397

$397

10 Min Spinning
Reserve

$209

$202

$202

$204

$206

$210

$214

$218

$223

$227

$231

$366

$366

$366

30 Min Reserve

$146

$142

$141

$143

$144

$147

$150

$153

$156

$159

$161

$256

$256

$256

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B-7

Arbitrage and T&D Values: The arbitrage values are based on the difference in the peak and off-peak values defined in the IESO
avoided costs study. The T&D deferral values are based on the IESO DER Potential Study.
2027

2028

2029

2030

2031

2032

2033

2034

2035

2040

2045

2050

Arbitrage Values($/MWh)Transmission
Deferral ($/kW-yr)

2026

Service Value

2025

Table 10: Arbitrage and T&D Values across the scenarios

$6

$20

$10

$13

$13

$18

$20

$20

$18

$23

$23

$61

$55

$55

$44

$45

$46

$47

$48

$49

$50

$51

$52

$53

$54

$60

$52

$52

B.4 LDES Technology Characterization
We recognize that different types of long-duration energy storage (LDES) technologies are available in the market today, eachwith different storage or physical principles and architectures. To capture the extent of their technical capabilities, we haveassumed a range to capture the broad array of LDES performance characteristics. The following table captures the key
assumptions on the sensitivity of the technical parameters.
Table 11: LDES Technical Assumptions

Parameters

Low Cost

Duration

Base Costs

High Costs

10 hours

Degradation Rate

-%

1%

2%

Round Trip Efficiency (AC-AC)

75%

65%

53%

Project Life
2032 Capital Cost (CA$/kW)
Fixed O&M ($/kW-yr)

30 years$2,740$3,295$4,00027 $/kW-yr

33 $/kW-yr

40 $/kW-yr

B.5 Net Cost of New Entry Cost Calculations (Net CONE)
To estimate the Net Cost of New Entry, we first determine the Net Lifetime Costs of the marginal unit and the Net Lifetime
Revenues from the marginal unit.

𝑁𝑒𝑡 𝐶𝑂𝑁𝐸 ($𝑇𝑜𝑡𝑎𝑙 𝐿𝑖𝑓𝑒𝑡𝑖𝑚𝑒 𝑃𝑟𝑒𝑠𝑒𝑛𝑡 𝐶𝑜𝑠𝑡𝑠 − 𝑇𝑜𝑡𝑎𝑙 𝐿𝑖𝑓𝑒𝑡𝑖𝑚𝑒 𝑅𝑒𝑣𝑒𝑛𝑢𝑒𝑠− 𝑦𝑟) =
𝑘𝑊
𝑈𝑠𝑎𝑏𝑙𝑒 𝐶𝑎𝑝𝑎𝑐𝑖𝑡𝑦 × 𝐿𝑖𝑓𝑒𝑡𝑖𝑚𝑒 (𝑌𝑒𝑎𝑟𝑠)

For each generation unit, we calculate the total lifetime83 present costs.

𝑇𝑜𝑡𝑎𝑙 𝐿𝑖𝑓𝑒𝑡𝑖𝑚𝑒 𝑃𝑟𝑒𝑠𝑒𝑛𝑡 𝐶𝑜𝑠𝑡𝑠= 𝐶𝑎𝑝𝑎𝑐𝑖𝑡𝑦 𝐶𝑜𝑠𝑡𝑠 + 𝐹𝑖𝑥𝑒𝑑 𝑎𝑛𝑑 𝑉𝑎𝑟𝑖𝑎𝑏𝑙𝑒 𝑂&𝑀 + 𝐹𝑢𝑒𝑙 𝐶𝑜𝑠𝑡𝑠 + 𝐶𝑎𝑟𝑏𝑜𝑛 𝑇𝑎𝑥 𝐿𝐼𝑓𝑒𝑡𝑖𝑚𝑒
For each generation unit, we calculate the total lifetime present revenues, which, in this case, we assume only the energy
revenues84.

𝑇𝑜𝑡𝑎𝑙 𝐿𝑖𝑓𝑒𝑡𝑖𝑚𝑒 𝑅𝑒𝑣𝑒𝑛𝑢𝑒𝑠 = 𝑇𝑜𝑡𝑎𝑙 𝐸𝑛𝑒𝑟𝑔𝑦 𝑅𝑒𝑣𝑒𝑛𝑢𝑒𝑠
2030 Assumptions
Natural Gas
CCGT

Natural Gas CCGT
(85% CCS)

Natural Gas
PeakerGreen H2
PeakerBlue H2
PeakerSMR

Capacity Factor

80%

80%

15%

15%

15%

93%

Capacity Costs ($/kW)$1,367$3,581$2,215$2,215$2,215$11,530

Fixed O&M Costs ($/kW-yr)

$19

$62

$40

$40

$40

$150

Variable O&M Costs ($/MWh)

$3

$13

$9

$9

$9

$5

Fuel Costs ($/MWh)

$24

$46

$85

$453

$531

$9

Carbon Tax ($/MWh)

$56

$8

$48

83
84

Assumes a discount rate of 6%
Assumes energy revenues of $75 per MWh over 2025 to 2050. Higher energy costs assumed since Ontario is expected to be energy constraint.

“NO DISCLAIMERS” POLICYThis report was prepared by Dunsky Energy + Climate Advisors, an independent firm focused on the clean energy transition andcommitted to quality, integrity and unbiased analysis and counsel. Our findings and recommendations are based on the best
information available at the time the work was conducted, as well as our experts' professional judgment.
Dunsky is proud to stand by our work.