IESO 2022 Annual Planning Outlook Summary and Commentary

December 22, 2022
Travis Lusney, Kausar Ashraf, Brady Yauch

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December 22,2022

To:         Clients and Colleagues

From:    Travis Lusney, Director Power Systems

             Kausar Ashraf, Senior Manager, Energy Transition

             Brady Yauch, Senior Manager, Markets and Regulatory Affairs

Re:         IESO 2022 Annual Planning Outlook Summary and Commentary


The Independent Electricity System Operator (IESO) published the 2022 Annual Planning Outlook (APO) providing an outlook on Ontario's electricity system plans and future system operations.

This note provides Power Advisory’s summary and commentary on the 2022 APO. In previous APOs, the IESO has provided multiple scenarios. In tandem with the 2022 APO, the IESO published the Pathways to Decarbonization (P2D) report. Power Advisory views the 2022 APO as the IESO reference case (i.e., a business-as-usual outlook based on existing policy and regulation) and the P2D as the high-demand case based on anticipated and future net-zero policies.

The APO provides stakeholders with the data and analysis to make informed decisions based on future system needs (i.e., over the next 20 years). It also provides policymakers with the information they need to craft policy for the province’s electricity sector. The 2022 APO includes seven sections: demand forecast, supply and transmission outlook, resource adequacy, transmission security, integrating electricity needs, outcomes and other considerations, and uncertainties.

The P2D Report is the IESO’s response to the Ministry of Energy to evaluate a moratorium on new natural gas-fired generation in Ontario, as well as developing a pathway to zero emissions in the electricity sector – looking out as far as 2050.

Demand Forecast

The APO continues to forecast an approximate 2% annual net energy demand growth, from 147 TWh in 2024 to over 208 TWh by 2043. In the near term, the system continues to experience a summer peak, with a winter peak emerging in 2037 as a result of space heating electrification. This is a faster acceleration than what was published in the previous APO, where the system became winter peaking in 2042. The IESO continues to project demand growth at levels greater than last decade as a result of economic development due to industrial growth and climate policy offsetting increases in energy efficiency investments.

Figure 1: Energy Demand by Sector

Figure 2: Seasonal Peak Demand

Similar to last year’s APO, demand growth is a result of electrification trends in transportation and decarbonization investments in mining and industrial manufacturing. Industrial sector growth has the potential to be robust through new demand centers in the province’s steel-production, EV-production supply chain and hydrogen-production segments.

Notably, the IESO has highlighted the change in consumption patterns that it expects to occur over the next 20 years, particularly in the winter months. The new consumption patterns are largely a result of year-round battery EV charging and an increase in electric space heating in the urban centers. The combination of these two factors results in much higher demand in the evening-to-dawn periods. Changing consumptions patterns will influence what resources are needed to meet peak demand and maintain reliability, notably with resources that can ramp quickly and long duration energy resources.

Figure 3: Mid-Summer Business Day: Hourly Profile

Figure 4: Mid-Winter Business Day: Hourly Profile
Supply and Transmission Outlook

Ontario has 41,200 MW of installed supply capacity as of 2022, including both transmission-connected and embedded distribution-connected resources. Nuclear generation, gas-fired generation, and hydroelectric generation resources represent roughly a quarter of installed capacity each. The remaining installed capacity comes from wind generation (13%), solar generation (6%), and bioenergy generation (1%).

Figure 5: 2022 Installed Capacity by Fuel Type

The Ontario nuclear generation fleet will undergo significant change over the outlook period. Six generation units at the Pickering nuclear generation station (NGS) will retire between 2024 (2 units) and 2026 (4 units). In addition, the ongoing nuclear refurbishment program will see 9 generation units refurbished (G2 at Darlington NGS was returned to service in 2020). The outlook excludes the proposal to further operate the Pickering Nuclear Generating Station (NGS) beyond 2025, which will require approval from the Canadian Nuclear Safety Commission (CNSC), which Power Advisory expects to occur.

In addition to nuclear generation refurbishment, IESO contracts with generators will expire during the outlook period. The APO distinguishes between installed capacity, which is a resource’s maximum output, and effective capacity, which is the resource's expected capability to meet peak demand during a season (i.e., summer or winter). If generators do not remain in service after their contracts expire, the effective summer capacity of the supply mix drops from 25,000 MW in 2023 to 16,000 MW by 2042. The IESO produced two cases as a part of the supply assessment.

• Case 1 reflects resources until their contract/commitment period ends. It defines system needs met by existing resources. This case assumes that hydroelectric resources are available post-contract expiry.
• Case 2 includes the resources in Case 1, and assumes that these resources continue to be available post-contract/-commitment expiry for the duration of the study period. Case 2 helps identify minimal new incremental resources that will be needed to meet system needs.

Both cases assume a number of actions included in the latest IESO AAR. These actions include:
• Capacity from the IESO’s first Medium-Term Request for Proposal
• A 300 MW Small Modular Reactor at OPG’s Darlington nuclear site
• Hydro Quebec Capacity Sharing Agreement, utilizing the 500 MW capacity imports in the summer of 2026
• Government policy on biomass extensions
• Government policy on small hydroelectric program
• 2022 AAR Capacity Auction forward guidance targets
• Bilateral negotiations for Lennox GS and Brighton Beach GS

The figure below shows the summer effective capacities by fuel type for the outlook period in Case 1. Summer effective capacity varies between 27 and 29 GW during the 2020s due to the refurbishment of the nuclear fleet and then levels off at about 29 GW through 2043 due to contracts expiring.

Figure 6: Case 1: Summer Effective Capacity Without Contracted Resources

The bulk transmission system ensures Ontario’s supply resources can deliver energy to load centers and maintain the province’s resource adequacy criteria. Ontario is subdivided into ten electrical zones. To maintain the reliability of the bulk transmission system, several transmission projects have been planned for during the outlook period (see table and figure below).

Table 1: Planned Transmission Projects
Figure 7: Transmission Zones and Anticipated Transmission Projects

Transmission System Reliability

With capacity needs forecast to grow throughout the APO forecast, a robust transmission system will play an increasingly important role in ensuring that resources can supply demand both provincially and to customers locally. APO 2022 identifies transmission system issues that will limit the ability to reliably meet forecasted demand over the next 20 years, and triages these issues, identifying those that require further IESO bulk system planning and those that can be addressed by acquiring capacity in specific areas.

• Transmission Supply to the Greater Toronto Area (GTA)
• East GTA: Supply between Clarington TS and Cherrywood TS
• Essa Area Transmission System
• Transmission Issues in the Lennox–St. Lawrence Area
• Transmission Issues in Central-West Ontario (East of London)
• System Issues in Northern Ontario
• Interties with Neighbouring Jurisdictions

Resource Adequacy

Resource adequacy metrics ensure there are enough resources available to supply demand in any given hour, particularly during peak demand hours. The IESO performs a probabilistic resource adequacy assessment in comparing the demand forecast to the anticipated performance of supply resources to arrive at a Loss of Load Expectation (LOLE). The IESO maintains sufficient supply capacity in the system so that the LOLE is not greater than 0.1 days per year (one day of outages every decade).

The IESO also uses a reserve margin calculation to determine the amount of supply capacity above peak demand during normal weather conditions needed to maintain system reliability.  Even with the continued operation of existing generators, the 2022 APO’s forecast of reserve margin expects Ontario to have a deficit in reserve margin available by 2026 (following Pickering NGS retirement) – this is in stark contrast to the last decade when Ontario had large surpluses.
The APO also analyzes capacity adequacy in relation to demand and resource assumptions for both the summer and winter periods. A capacity deficit signals the need to acquire additional capacity to satisfy the LOLE requirement. Summer and winter capacity needs emerge in 2026 due to Pickering NGS retiring, outages from nuclear generation refurbishments, and increases in demand.

The capacity deficits for summer and winter periods for supply Cases 1 and 2 are shown in Figure 8 and Figure 9. Summer capacity needs emerge in 2026 with long-term needs being driven by nuclear retirements and refurbishments, resources reaching the end of their contracts and increased demand.

Figure 8: Summer Capacity Deficit

Figure 9: Winter Capacity Surplus/Deficit

In terms of potential energy supply needs, the province will be energy adequate up to and including 2028. This is a departure from last year's APO which stated that the province would have energy adequacy until the mid 2030s.

Figure 10 illustrates the potential for unserved energy, demonstrating that capacity needs identified also eventually lead to an energy need. Unserved energy occurs when requirements remain even after all generators have been fully dispatched (global unserved energy), or transfer limits have been reached (local unserved energy).

Figure 10: Unserved Energy

In Case 1, the potential for unserved energy begins to grow substantially in 2029, which is linked to the assumptions on the adoption of electric vehicles (EVs) by the end of the planning horizon – hitting about 84 TWh by the end of the forecast horizon. Case 2 also Illustrates an energy need, however, it reaches just 12 TWh by the end of the forecast horizon. This assumes contract extensions of all operating assets.

The IESO’s analysis assumes that domestic resources alone will not be sufficient to meet energy requirements, pushing Ontario towards becoming a net importer. Figure 11 illustrates the IESO’s forecast for imports (assuming there is availability from other jurisdictions). In Case 1 , imports increase to 16 TWh by 2028 up from today's 6-8 TWh. Should nothing change, Ontario will need to become more reliant on imports as there are evolving decarbonization policies which are expected to change supply mixes and therefore the energy production outlook. This will apply to Ontario and neighbouring jurisdictions.

Figure 11: Energy Production Outlook, Imports

Locational Considerations Based on Transmission System Limitations and Integrating Electricity Needs

For the most part, the locational considerations have remained the same as APO 2021. In addition to supply capacity requirements mainly driven by forecast provincial demand growth, there are locational capacity needs throughout Ontario’s transmission system due to local constraints. Capacity needs resulting from transmission security requirements are identified in the following regions.

West of London/West of Chatham Areas: This area was identified in the 2021 West of London bulk planning study. Forecasted demand growth in the IESO West electrical zone (southwestern Ontario), after considering the transfer capability of the Buchanan-Longwood/Negative Buchanan-Longwood (BLIP/NBLIP) transmission interface, creates a locational capacity requirement in the West of London area beginning in 2030. Part of this locational requirement is more specifically constrained within the area West of Chatham. The total locational capacity requirement West of London grows to 1,975 MW by 2035, of which 550 MW is in the Windsor-Essex and Chatham-Kent areas further west closer to the greenhouse loads (i.e., West of Chatham). This need does not assume the continued availability of resources after their contracts expire. The IESO will reassess the need following the conclusion of the Long-Term 1 RFP. The re-contracting of generation in Sarnia until May 2031 will shift the West of London need out by a year but will not materially change the overall need by 2035, nor the West of Chatham needs. To mitigate some of this need, the IESO has recently announced developing targeted energy efficiency in this area focusing on greenhouses, which could also alleviate this need.

East of the “Flow East Towards Toronto” (FETT) Interface: The IESO identified significant capacity needs east of FETT in the last APO. This area includes the Toronto, Essa, East, Ottawa, Northeast and Northwest electrical zones. Note: Should the Pickering NGS proposed nine-month extension be approved by the CNSC, it could address the capacity need forecasted to 2026. A localized capacity gap is forecasted to emerge within the GTA beginning in 2027. This issue affects several autotransformers supplying the load centre and is linked with other initiatives, such as the Northwest GTA Transmission Corridor Study. In the longer term, a capacity requirement east of FETT is expected to emerge by the end of the 2020s; however, the timing and magnitude of this requirement will need to be re-assessed following the conclusion of the Long-Term 1 RFP. Also, any resources that are sited in the GTA, as well as energy efficiency or demand management, will also help to push back the need while helping to alleviate the need east of FETT.

Ottawa Area: The IESO will implement the recommendations of the Gatineau Corridor End-of- Life Study. If completed on time, it will push the need to the mid 2030s; assuming the current demand forecast is accurate. As an outcome of the IESO Conservation Demand Management Mid-term review, this area Is being considered for targeted energy efficiency programming.

Northern/Northeastern Ontario: The IESO is currently conducting a mining study which will confirm the needs in the north of the province, west of Mississagi Flow West Interface. Additionally, the IESO has flagged any plans for this area will include development of hydroelectric resources.

Outcomes and Other Considerations

The APO indicates that with the planned outages from the refurbishment of units at Darlington NGS and Bruce NGS in the 2020s and 2030s, gas-fired generators will more often become the marginal resources in the wholesale market. Higher carbon prices and more operating hours from gas-fired generators are expected to increase both carbon emissions in the electricity sector and marginal costs. As such, the APO predicts greenhouse gas (GHG) emissions from the electricity sector to increase to approximately 10 Megatonnes (Mt) by 2028. This forecast has doubled since last year's APO (5Mt by 2030). This Is largely attributed to increased output from gas-fired generation to compensate for reduced nuclear generation and growing demand.

The APO notes, however, that increased electricity sector emissions do not necessarily mean higher Ontario economy-wide emissions because the province’s generation fleet is already relatively non-emitting. With electrification (i.e., switching from carbon-intense fuels to electricity such as EVs or space heating) economy-wide emissions may decrease. The 2022 APO aligns with the latest federal policy announcement of $170 per tonne CO2e by 2030.

Figure 12: Electricity Sector Greenhouse Gas Emissions, Historical and Forecast

Throughout the 2022 APO the IESO has highlighted a number of uncertainties that may impact its outlook. Most notable is the pace and timing of electrification. This will have a significant impact on electricity demand. Factors including industrial load growth, climate change policy and consumer preferences are likely to put upward pressure on demand. The P2D report highlights what would happen to demand should all these uncertainties materialize. Despite additional energy efficiency (5,000 MW) in the P2D demand forecast, electricity demand is projected to double and shift towards having three ramps per day (6,000 -10,000 MW) as opposed to today where there are two (2,000 MW - 5,000 MW).

In addition to increased pressures on electricity demand, there are several factors that will impact system adequacy. These factors include: market exit of an aging fleet, in-service delays for new generation projects, performance issues, outage management, the timing of nuclear refurbishment and retirements, supply chain delays, fuel availability, policy uncertainties and extreme events.

Figure 1 illustrates the difference between the APO 2022 demand scenario and P2D demand scenario. In the P2D scenario, there is an average annual growth rate for 2023 - 2050 of 2.7 percent for energy, reaching an annual energy consumption of approximately 300 TWh by 2050 (from around 140 TWh today), as shown in Figure 13.

Figure 13: Comparison 2022 APO and P2D Net Annual Energy Demand

Peak demand increases by 1.5 percent per year for summer (Figure 14) and 3.8 percent for winter, resulting in a winter peak of approximately 60 GW by 2050 (Figure 15) (up from around 23 GW today).

Figure 14: Comparison 2022 APO and P2D Annual Summer Peak Demand
Figure 15: Comparison of 2022 APO and P2D Winter Peak Demand

Power Advisory Commentary

The 2022 APO and the P2D – along with the IESO Conservation and Demand Management-Mid-Term Review (CDM-MTR) Report – are three foundational documents, providing stakeholders with various details, assumptions and outlooks on how the system may evolve over the next two decades. Building upon last year's APO, the 2022 APO provides an outlook for Ontario in which electricity demand continues to grow and must be supported by developing new supply resources. This message is reinforced in the P2D report, which highlights higher demand growth due to a shift in climate change policy and emphasizes fuel-switching to encourage decarbonization. Lastly, the IESO Conservation and Demand Management-Mid-Term Review (CDM-MTR) Report highlights the role energy efficiency programming can play in reducing demand growth. All three reports acknowledge the Minister of Energy's letter requesting consideration to reduce the reliance on emitting resources in the province.

Figure 16 illustrates the difference between the IESO Demand Forecast and Power Advisory's forecast. In Power Advisory’s view, while the demand outlook presented by the IESO is reasonable and pragmatic given today’s economic circumstances and policies, the full extent of electrification trends are not included in the APO forecast but are reflected in some capacity in the P2D demand forecast. Power Advisory expects higher summer peak demand growth in the Base and Net Zero case compared to the IESO. This Is largely due to the expected increase in electric vehicle load. Although programs are in place to shift this load to off-peak hours, the Power Advisory forecast assumes a higher summer peak contribution for electric vehicles than the IESO's. In Power Advisory’s view the ability to shift summer peaks becomes limited as large quantities of EVs are deployed and attempt to charge all at the same time. Further, the 2022 APO does not appear to consider the impacts of commercial fleets that likely will be charging consistently as part of operational optimization (i.e., replace a fully charged vehicle with a depleted vehicle as soon as possible). Power Advisory also includes more industrial and mining growth, in line with the High Demand scenario from the 2021 APO. For the next iteration of IESO APO, the APO should more clearly model a range of assumptions on electrification trends, as it has been signalled in both consumer choice and government policy. Electrification will be the driving force of change in the province’s grid over the next two decades and the potential scenarios should be reflected and analyzed in the APO.

Figure 16: Comparison of Net Summer Demand Outlooks

For example, the IESO reports lack assumptions regarding the adoption of commercial electric fleets as well as charging networks. This is a critical assumption that will impact supply need and operability assessments.

The IESO highlights in this year's report that the need for energy supply has accelerated to 2028 compared to the previous projection of the mid-2030s. The previous projection underpinned the IESO’s decision to focus its procurements on capacity products only. As the energy needs continue to grow, the IESO will need to contemplate a procurement process with more consideration for energy resources, particularly non-emitting resources in the near-term (i.e., solar and wind generation). Long-term energy needs are likely to be mostly addressed by refurbished (i.e., Pickering NGS ) and potentially expanded nuclear capacity (e.g., SMRs). Following the 2007/2008 recession, Ontario experienced a loss of industrial demand that resulted in fairly flat demand growth (along with Behind-The-Meter supply). After a decade of slow growth, demand for electricity is expected to reach unprecedented levels. Ontario is potentially well positioned to support the global energy transition as it already has a robust automotive sector coupled with being rich in critical minerals in northern Ontario. The challenge will be developing these sectors while maintaining a safe, reliable, clean and cost-effective electricity system. These sectors are projected to grow significantly, and it is critical the IESO model this growth using the best and most recent data available and/or produce scenarios. Under-forecasting demand growth will inherently result in procurements for products that are not appropriately addressing the system's needs – posing a reliability risk and unnecessary cost to ratepayers.

Figure 17: Ontario Supply Need Projections (with continued availability of existing resources)

The 2022 APO shows a lower supply need compared to APO 2021 under both the Reference and High Demand scenario. While the demand outlook for 2021 APO Reference Case and 2022 APO are similar, the supply outlook assumptions have changed. The commitment to enhanced procurement of capacity through the Capacity Auction – roughly 1,500 MW in the summer annually – is the primary reason for the reduction.  The Capacity Auction only secures commitments for two 6-month periods and therefore there are risks in treating its procurement as a long-term committed resource. Clearly there is significant opportunity for demand-side resources through the Capacity Auction but the treatment of those resources under long-term planning is not appropriate in Power Advisory’s view. Capacity Auction resources should be a swing resource that is adjusted up-and-down (with an appropriate floor amount to maintain resource capability) to reflect current system conditions. If long-term, and more cost-effective resources can be procured, the IESO should seek them out.

Figure 18: Comparison of Installed Capacity Between 2021 APO and 2022 APO

APO Reports have been publishing a capacity need since 2019. Originally the need was driven by the potential retirement of Pickering NGS. However, since 2019, electrification trends have increased demand outlooks resulting in both capacity and energy needs accelerating. A critical issue in Power Advisory’s view is that prioritizing capacity before energy is adding unneeded complexity and potentially putting the cart before the horse. Capacity needs are defined by expected output during peak demand and other constrained hours from the supply mix. Adding resources to meet energy needs defines the supply mix which would then be used to determine capacity needs. Perhaps more importantly, ensuring that the supply mix for energy is more cost-effective can have important influences on capacity needs. For example, new renewable generation could be procured to lower average energy costs for customers. Depending on the amount and type of renewables procured, the capacity need would vary. Given the challenge of managing the potential continued operation of resources with expired contracts, it would be prudent for the IESO to seek out the lowest cost energy resources to meet both future energy needs and to lower average energy costs. This would also allow the IESO to explore supporting investments in existing flexible generation resources (e.g., gas-fired generation) to meet future system needs.

Figure 19: Gas-Fired Generation Annual Capacity Factor Forecast

The energy need may be understated by the 2022 APO. Comparing installed capacity to expected annual output for gas-fired generation, the IESO appears to assume that the annual output of these resources will increase three-fold over the next two decades, and double by 2026 (under Case 1 with all existing resources continuing to operate). Some of this increase is reasonable to fill the energy gap while nuclear refurbishments are completed. The primary risk is many of these gas-fired generation resources are over 15-years old and continued operation will require capital investments. Without a clear procurement path, it is not certain these assets will be capable of operating at these elevated annual capacity factors. Further, outage times for regular maintenance will be longer and may be difficult to schedule while supply conditions tighten. Currently the IESO is flagging outage management concerns in their quarterly Reliability Outlooks, and the issue will only intensify in the future. Future procurement processes will need to consider what is possible from existing resources and recognize the need for investments, sometimes with substantial capital requirements, for continued operation.

Currently, the IESO is re-contemplating their strategy for LT-1 RFP and are likely contemplating the impacts of this assessment before sharing next steps. Given the fast-approaching supply need for new resources, the IESO will need to consider a process for contract extensions to minimize the potential expansion of the supply need. Further, there is potential to re-power existing facilities to higher capacity using the same interconnection point and community acceptance. So far, little to nothing has been released by the IESO on re-powering or re-contracting options.

Given the heightened uncertainty and history of changing electricity policy direction within Ontario, a consistent procurement process with a long-term roadmap will help all asset owners, developers and policy makers understand the breadth of resource options – both from continued operation, re-powering, and new build. A consistent procurement process can also allow the IESO to adapt to changing system conditions, policy needs and innovative offerings. Outcomes from each procurement round can be adjusted to suit both near-term and long-term needs, including decisions that are broader than the electricity sector (i.e., social-economic decisions by government).  Flexibility is needed within the procurement process so that innovation and cost savings can be realized.

Hanging over all of the system needs is the significant change being undertaken to the wholesale market design through the Market Renewal Program. The IESO has now shifted the implementation date of Market Renewal to end of 2025, when many of these new resources are expected to come into service. Market design risk and future revenue uncertainty are significant challenges for project developers and financiers of energy projects. Addressing these risks and uncertainties through contract design are going to be an ongoing challenge for the IESO and proponents for the foreseeable future.
Taking a step back, the 2022 APO re-iterates a number of near-term certainties for the Ontario electricity sector:

• New supply resources will be required by the mid-2020s and growing through the 2030s.
• The role and potential investment in existing resources will need to be addressed to ensure the supply need for new build resources does not grow significantly.
• Long-term energy solutions, primarily nuclear generation, are being explored by the government-owned generation company, Ontario Power Generation. This seems prudent given the potential large demand growth from decarbonization.
• Transmission investments are expanding rapidly and new opportunities could appear.
• The Market Renewal Program increases uncertainty for market participants and for procurement processes.