Regulation and
risk:
Overcoming uncertainty
Executive summary
Investing in our energy future has many challenges. Important variables like government policy, consumer preferences, and technology adoption impact investment risk for utilities. Uncertainty in capital access, revenue, and regulation also create risk for those looking to invest to meet the needs of our changing energy system. Regulatory mandates aim to ensure safety, reliability, customer value, and the long-term viability of service providers, thus managing and mitigating investment risk must be a primary focus of regulators throughout Canada. Regulators have the authority and tools to support effective utility investment.
Utilities are facing immense policy pressure regarding affordability concerns yet, simultaneously are encouraged to make major investments in the grid. This balancing of investment and affordability is a serious concern for utilities, as they are faced with a changing energy landscape. Replacing, upgrading, maintaining aging infrastructure is a significant investment for all utilities.
Investment risk
Investment risk is the potential for financial instability resulting from utility investment in areas of high uncertainty. Risk stems from capital recovery challenges and long-term uncertainty in planning, as well as impacts like technological change and policy directives.
When regulators do not sufficiently account for the impacts that government policy and broader industry trends have on utility investment requirements, the utility cannot effectively manage the costs and risks associated with investment. Regulatory reforms that help reduce investment uncertainty and align priorities between utilities, customers, and regulators can have a positive effect on promoting investment and reducing a utility’s exposure to commercial risk.
This report will explore investment challenges and outline specific measures, tools, and approaches regulators can utilize to overcome those factors, to best serve the public interest.
In coordination with our members, and through discussions with a variety of stakeholders, Electricity Canada has identified three areas of focus for these investment challenges
Electrification and load growth
Electrification and load growth
Grid modernization
Climate adaptation
Across the country, electricity demand growth is a trend in all jurisdictions. Both national and provincial forecasts suggest a near doubling of demand growth over the next 25 years.
Governments, system operators, and service providers are rapidly adjusting their future electrification projections to account for these significant shifts in demand. Policy, regulation, and broader market trends are shaping electrification in Canada, but misalignment between regulator and utility priorities exacerbates underlying market uncertainty. Major increases in expected load growth over the next decades requires dramatic investment from electricity service providers, positioning the sector as an energy investment leader. To manage these investment pressures, utilities will need to have sufficient access to capital, as well as revenue models and regulatory frameworks which reduce the heightened investment risk caused by public policy and changing demand.
Grid modernization
Throughout Canada, customer needs are driving modernization efforts. The electricity system is changing dramatically; in the kinds of technologies that are being used, systems that are being operated, and the preferences of customers.
Investing in grid modernization helps manage this diverse electricity system. Grid modernization is a crucial investment necessary to address current and future challenges related to safety, reliability, and affordability.
However, these investments are challenged by misaligned policy and regulation. As customer needs drive modernization efforts, current regulatory priorities are not directed at optimizing fundamental grid modernization investment across Canada due to the substantial variance in the approaches taken by individual jurisdictions. Regulatory priorities and investment direction for utilities should recognize that grid modernization is required to serve future customer needs and achieve policy goals.
Climate adaptation
The increased threat of severe weather and wildfires creates a heightened risk for utility asset management, including system reliability and resiliency. Climate related risk is an ever-growing concern for utilities, particularly as service providers are looking to substantially invest in assets and systems to manage load growth and grid modernization needs.
Prioritizing climate change adaptation investment reduces risks related to reliability, cost recovery, and, ultimately, affordability. Climate adaptation must also be understood within the broader context of challenges, as utilities address competing priorities with limited budgets. Regulators should consider these priorities and be prepared to provide guidance on how to approach these trade-offs, when pursuing climate adaptation investment, as utilities must balance reliability investment and affordability.
The cost and benefits of climate adaptation must also be quantified so that utilities and regulators understand the value of climate adaptation investments in clear financial terms. Regulators can implement strategies and tools to support utilities in managing this investment risk and reduce the impact of broader climate risk.
Regulatory measures to reduce investment risk
While load growth, grid modernization, and climate adaptation are common concerns for the entire electricity sector, the varying ownership and regulatory structures of each province impact the kinds of regulatory innovations available. While some recommendations are more applicable to investor-owned utilities, others are more applicable to publicly owned utilities the suite of recommendations serves to capture an overarching perspective of the challenges facing Canada’s electricity sector. However, for all utilities, regulatory bodies play a key role in setting standards and requirements for essential grid investments and are central to mitigating and managing investment risk.
Regulatory measures to reduce investment risk in electrification and load growth
Attract private investment to reduce risk
\ Allow for the increased use of mid-project cost recovery mechanisms
\ Encourage stable economically regulated environment through an increased return on equity
Use flexible accounts and increase assessment thresholds
\ Use tailored accounts to reduce financial uncertainty
\ Increase assessment thresholds for cost recovery to support regulatory efficiency
Promote optimal utility management within existing regulatory frameworks
\ Use more non-adjudicative tools to increase regulatory certainty
\ Integrate policy impacts at all levels into rate decisions
Regulatory measures to reduce investment risk in grid modernization
Promote grid modernization expenditure through incentive mechanisms
\ Use clear regulatory policy guidance to achieve government and regulatory priorities
\ Approve investment plans and offer targeted funding mechanisms
Standardize assessment frameworks to increase certainty around investment
\ Use robust Benefit-cost analysis and complementary policy frameworks to provide greater certainty for Non-Wire Alternative investments
\ Optimize investments in Non-Wire Alternatives by allowing relevant operational expenditures incentive payments
Accommodate a greater degree of novel innovation expenditure
\ Implement innovation sandboxes with sufficient financial support
\ Approve individual utility innovation accounts funded through the rate base
Regulatory measures to reduce investment risk in climate adaptation
Support resiliency though long-term strategic investment priorities
\ Ensure hard asset and operational climate management expenditure is at an effective level
\ Mediate affordability concerns with long term risk evaluation
Support sufficient cost recovery measures
\ Establish sufficient climate recovery funds based on forward looking climate plans
\ Efficiently approve climate related cost overruns for inclusion in the rate base
Evaluation and management frameworks that promote data driven investments
\ Implement a value of lost load (VOLL) framework to serve as an effective tool to justify expenditure
\ Implement climate adaptation management plans that use a consistent approach across the sector
Electrification and load growth
Across the country, utilities are experiencing electricity demand growth, resulting from the increased electrification of home, transportation, and industrial energy consumption and the broader adoption of new technologies. Both national and provincial forecasts suggest a near doubling of demand growth over the next 25 years. While there is substantial regional variation due to current generation makeup, technology adoption, and projected population growth, a general growth trend is consistent across all jurisdictions. Governments, system operators, and service providers are rapidly adjusting their future electrification projections to account for significant shifts in demand.
Broad electrification driven by energy switching is a significant driver of demand growth. New large loads like data centres are also becoming an increasing challenge for utilities to supply and manage. Another key consideration is the impact of population growth and greater population density as consistent drivers of load growth. Not only is the energy demand per customer changing, but total demand growth independent from the rate of technological change is a challenge for the sector.
Looking at Canada’s national forecast (Figure 1) we see that electricity demand is expected to grow by 80% from 2025 to 2050, most of it from new areas such as electric vehicles (EVs). While exact load growth is dependent on many variables, the standard trend still demonstrates requirements for large-scale investment and capacity growth.
To manage these investment pressures and the risk of uncertainty, utilities will need to have sufficient access to capital, as well as revenue models and regulatory frameworks which reduce the heightened investment risk caused by public policy and changing demand.
Forecasts not only show major demand growth, but these are also changing rapidly adding a greater amount of uncertainty and investment pressure to a capital-intensive and regulatory-constrained sector. These adjustments in growth forecasting create uncertainty around the location, timing, and quantity of investment required:
\ In 2024, Ontario’s Independent Electricity System Operator (IESO) increased their forecast for anticipated electricity demand growth by 15 per cent from 60% to 75% growth of current demand by 2050.ii When the IESO changed this projection, they cited this increase in expected load from data centres.
\ Alberta’s Electricity System Operator (AESO), in a 2024 forecast, estimated a 23% (1.2% year over year) growth in average hourly load by 2043 in base-line projection. This base-line projection has tripled since their 2022 forecast. iiiIf this rate of growth continues to 2050, this could account for an approximate 30% increase in load growth.
Figure 1: National Demand Forecast by Sector (Canada Net-Zero Scenario)i
Figure 2: Potential Electricity Demand/Load Growth Rates by 2050 for Provinces with
Extended Forecasts
(Figure 2): Quebec: Nearly 100% increase in demand growth by 2050;iv British Columbia: Nearly 100% increase in demand growth by 2050;v Ontario: 75% increase in demand growth by 2050;vi Alberta: 23% growth by 2043, if assumptions continue to 2050 then a 30% increase in load growth is expected.vii *Other provinces did not have forecasting data that extend to out to 2040.
Major considerations in economic regulation
Regulatory and policy environment
Within the current regulatory regimes across Canada, there is substantial variation in the tools and tactics used to support innovation in the sector and help utilities manage growing investment pressure resulting from current and forecasted demand growth. Across the board, regulators need to incorporate the impacts of policy changes, such as electrification goals or climate policies, into decision-making at provincial, federal, and municipal levels.
Electricity service providers are generally policy neutral when it comes to the approaches aimed at managing the changing energy landscape, but the impact of policy on investment risk must be understood as it has material consequences for both utilities and for customers. Economic regulation affects investment pressures and commercial risk, particularly if regulators do not actively incorporate these policy considerations into their regulatory assessments.
Many jurisdictions have incorporated increased load growth forecasting into their investment planning but across the country, there remains substantial variance in these projections. In some cases, provinces have seen a slower increase in demand growth than what was expected. This is in part due to geographic and climate constraints as colder Canadian cities face challenges in broader EV adoption. Lower expected population growth rates and industrial growth rates in some jurisdictions have also led to more modest demand predictions.
Faced with affordability concerns, many provincial governments have moved forward with rate pauses and price caps. Managing this, while facing investment pressures, is a challenge for utilities. For example, in Manitoba the government has put a pause on rate increases yet, is directing greater investment in utility owned and operated EV chargers.viii In Nova Scotia the province introduced a rate cap, which resulted in a downgrade in Nova Scotia Power’s investment rating, hindering the utilities’ ability to attract lost cost funding. Government policy is having a direct effect on investment outlooks for utilities, and this impacts customer value.
Regulatory approaches to reduce risk
Quebec
New provincial legislation would allow Hydro-Québec to enter new power supply contracts without an open bidding process. This reduction in regulatory burden targets greater adaptivity in response to demand growth.
Ontario
The Ontario Energy Board (OEB) has been responsive to the investment needs of future load growth by approving substantive variance accounts for utilities to help manage risk.
Alberta
Alberta is undergoing energy market reform with a day-ahead market structure. The day-ahead market is intended to increase the reliability of the grid without having major price spikes through supply shortages.
Electric Vehicles (EVs)
Investment in grid capacity for electric vehicles is a major challenge for utilities. Regulation and policy are having a dramatic effect on Canada’s EV landscape. While the sector is policy neutral to these approaches, the impact of EV policy on investment risk should be incorporated into regulatory assessments.
As outlined in the Figure 1 a major part of forecasted electricity demand growth over the next 25 years can be attributed to the increased adoption of EVs. While policies may change and evolve, EV adoption is still predominantly driven by market trends, thus investment in grid infrastructure to support this increased demand is a necessity.
Large loads
The emergence of new large loads, such as data centres, is having a notable impact on load growth forecasting. There are currently over 250 data centres across Canada, a number that is growing rapidly. ixOntario’s load growth projections included 16 new energy-intensive data centres that are expected to online by 2035, comprising 13% of the new growth in electricity demand.x As well, the enhanced integration of AI-powered data centres into the grid, and the greater dependency these centres have on the electricity system, lead to amplified risk from cybersecurity threats.
Figure 3: Data centre map
The intensive computing needs of AI workloads are significantly driving this surge in demand, something that the Canada Energy Regulator has outlined in recent assessments.xi This has had a particular impact on Ontario growth projections, but there is also a notable uptick in data centres in Quebec, British Columbia, and Alberta. New Brunswick has already banned electricity service to cryptocurrency mining amid concerns about ratepayer risk, and continues to receive proposals for large loads like data centres coming on to the grid.xii And in Quebec, through recent proposed legislation, the government seeks to make projects of 5 MW or more subject to approval by the Minister’s Office, making load connection a decision at the political level.xiii
Indigenous participation in grid growth
Supporting Indigenous participation in the electricity sector is also a key consideration for reducing investment uncertainty and aligning stakeholder priorities. Regulators can take an active role in aligning revenue and value sharing mechanisms with investment strategies that promote reconciliation. Reconciliation must be a consideration for future resource planning as Canada’s energy system undergoes substantial change over the coming decades as Indigenous communities already have a major stake in policy and regulation effecting electrification and load growth.
Over the last eight years the number of medium and large Indigenous clean energy projects has grown by over 30%, and most of the generation and transmission projects in Canada have some level of Indigenous participation.xiv Joint business ventures and equity partnerships are a key feature of Indigenous participation in Canada’s expanding grid, and the unprecedented investment required in the electricity sector represents a major opportunity for Indigenous communities.
Non-adjudicative tools
Throughout Canada different policy and regulatory tools are used to manage our changing energy system. Nonadjudicative guidelines and frameworks are tools that can be deployed within exiting regulatory systems. The Ontario Vulnerability Assessment and System Hardening (VASH) project is an example of a non-adjudicative process. It aims to develop policies that quantify value for customers when prioritizing investments in system enhancements for resilience purposes. Tools like this allow utilities to have greater certainty around investments choices before rate cases.
Flexible accounts and cost recovery
Deferral and Variance Accounts (DVAs) can also help to manage cost uncertainty and reduce short-term financial strain if correctly implemented. As new projects can be lengthy, having access to these accounts reduces the impact of uncertainty and unplanned costs. Utilities can start collecting money spent on projects earlier in the development process, smoothing the cost recovery period. While some utilities have challenges with DVA’s due to their large balances and recovery challenges, strategic clearance of DVA balances can avoid financial burdens coinciding with rate rebasing.
This is also an important consideration for Capital Work in Progress (CWIP) accounts. In Alberta and Ontario, in specific circumstances, utilities have allowed CWIP to be included in the rate base, earning a return to address the cash outlay of large projects. These types of flexible cost recovery mechanisms can be an asset in managing the increased uncertainty of our changing energy landscape.
Deferral and Variance accounts (DVAs)
Deferral Accounts: track the cost of a project, where the utility can request approval to recover the costs through future rates.
Variance Accounts: track the difference between the expected cost and actual cost of a project. If the cost is higher, then the utility can request approval to recover the overage through rates.
Capital assessment thresholds
The challenge some jurisdictions face with regulatory efficiency is the expenditure point that capital cost thresholds kick in. Within certain parameters, capital expenditure does not have to be evaluated and approved by the regulator. But many provinces have stagnated thresholds, which have not accounted for inflation or increased investment pressure. This results in moderate capital expenditure requiring individualized regulatory evaluation, leading to inefficiency and a greater degree of uncertainty.
The capital pre-approval threshold in Nova Scotia is $1 million, and in New Brunswick projects over $50 million require regulatory approval. While there is substantial variance between these thresholds, both can be reached quickly for capital intensive projects. Capital thresholds are also used in evaluating Non-Wired Alternatives (NWAs) in Ontario. Distributors must document their consideration of NWAs when making investment decisions with an expected capital cost of $2 million or more. Increasing these thresholds allows utilities to be more adaptive and responsive to shifting energy demand, reducing regulatory burden and increasing certainty around investment approvals.
Return on capital
Cost of Capital (CoC), or Rate of Return (ROR) is the weighted average cost of equity and debt in proportion to the capital structure (debt/equity ratio) of the company.
Return on Equity (ROE) is the rate of return on equity. The ROE must be at a level that enables the utility to attract investors. ROE must meet the Fair Return Standard.
Fair Return Standard (FRS) has three requirements: comparable investment requirement; financial integrity requirement; capital attraction requirement.
Regulatory measures in load growth
Attracting private investment to reduce risk
Recommendations:
\ Allow for the increased use of mid-project cost recovery mechanisms: This helps manage investment pressures by allowing partial returns before project completion, improving cash flow and attracting private investors. These recovery mechanisms can also help utilities improve credit metrics, which benefit ratepayers through reduced utility borrowing costs. Mid-project recovery has a natural smoothing effect, further reducing financing costs otherwise paid by ratepayers over time.
\ Encourage stable economically regulated environment through an increased return on equity: This reduces financial risk, lowering borrowing costs and improving credit ratings. Equity Risk Premium (ERP) incentivizes longterm investment, making utility stocks more attractive compared to risk-free assets. A higher CoC is essential for financing to meet load growth. Without competitive returns, utilities may struggle to attract investment, delaying critical infrastructure upgrades.
Use flexible accounts and increase assessment thresholds
Recommendations:
\ Use tailored accounts to reduce the financial uncertainty: This can reduce short-term financial strain, as new projects to manage load growth can be lengthy. Having access to accounts, like innovation and variance accounts, reduces the impact of uncertainty and unplanned costs.
\ Increase assessment thresholds for cost recovery to support regulatory efficiency: Capital cost assessment thresholds in some jurisdictions have stagnated, resulting in low triggers for the regulatory assessment of capital expenditure. Increasing these thresholds to better account for inflation and changing investment requirements supports regulatory efficiency and creates greater certainty for moderate capital allocation.
Promote optimal utility management within existing regulatory frameworks
Recommendations:
\ Use more non-adjudicative tools to increase regulatory certainty: Non-adjudicative guidelines and frameworks can provide greater certainty to utilities, allowing service providers to direct internal effort towards projects that they believe have a high likelihood of being included in the rate base, promoting regulatory efficiency. By adopting more non-adjudicative frameworks, regulators can provide utilities with greater flexibility to implement innovative solutions and reduce investment risk.
\ Integrate policy impacts at all levels into rate decisions: Regulators should consider the impacts of policy changes, such as electrification goals or climate policies, at not only on the provincial level but the federal and municipal levels as well. By considering the broader policy landscape in rate-setting, regulators can provide utilities with clearer guidelines on expected returns for investments that align with the totality of investment pressures. This reduces risk by ensuring utilities are adequately compensated for the cost of meeting evolving policy demands and are less likely to have proposed investments rejected.
Grid modernization
As the Canadian economy undergoes greater electrification with increased integration of new technologies and systems into the grid, substantial investment will be required for grid modernization. Grid modernization advances and automates real-time grid operations to continue to balance and enable new connections. Modernization investments optimize network operations and support the more efficient use of resources over the long term, resulting in lower costs for customers. Throughout Canada, customer needs are driving modernization efforts. Investments in grid modernization help manage a more diverse electricity system, which is emerging out of our shifting energy landscape. Grid modernization is a crucial investment necessary to address current and future challenges related to safety, reliability, and affordability.
The scale of grid modernization costs might be small relative to load growth investments, but utilities still face pressures for grid modernization from customers, policymakers, and regulators. Customer preferences are shifting as they look for more opportunities to self-generate and better manage their energy use.xv Insufficient investment in grid modernization can lead to diminishing service quality, decreasing value for customers and long-term challenges for utilities managing future resources.xvi
Policy and regulation are having a major impact on the grid modernization landscape. Policy incentives and mandates that target increased renewable generation, energy efficiency gains, and the adoption of grid modernization tools and systems require grid modernization.
Government policy that incentivizes the adoption of new systems and technologies must be accompanied by parallel investments in traditional and non-traditional infrastructure to ensure distribution systems can reliably balance supply demand.
Economic regulation must also evolve to accommodate the new ways customers interact with the grid, balancing the disproportional short-term benefit early technology adopters receive from grid investments and the long-term benefits for the whole customer base.
Current regulatory priorities are not directed at optimizing fundamental grid modernization investment across Canada, because of the substantial variance in the approaches taken by individual jurisdictions. The use of clear regulatory frameworks and tools help minimize the impact of changing government policy and consumer preferences on investment risk and enhances certainty around investments. Regulatory priorities and investment direction for utilities should recognize that grid modernization is required to serve future customer needs and achieve policy goals.
Figure 4: Grid modernization infographic
Addressing investment challenges for grid modernization requires fostering a regulatory environment that encourages innovation and clearly identifies investment benefits. Sandboxes for innovation, transparent incentive structures, and jurisdiction-wide strategies with modernization plans can help bridge the gap, ensuring utilities are equipped to meet future energy demands effectively. Grid modernization investments are essential for utilities to manage our changing energy landscape and provide substantial value to the customer, but due to a lack of regulatory measures that incitive an enable these investments, grid modernization is still an issue of risk and uncertainty for many service providers.
Advanced Metering Infrastructure (AMI)
Some provinces began the process of adopting smart sensors and Advanced Metering Infrastructure (AMI) over a decade ago, while others have just recently started these modernization efforts. This variance in smart grid deployment provides opportunities for jurisdictions newer to this process to learn from past programs. For example, Manitoba Hydro is exploring how to support provincial government policy to evaluate and implement options to enable customers to save on their energy bill through opt-in demand management programs, but the province currently lacks the AMI to support such programs on a large scale.xvii Utilities are facing immense policy pressure regarding affordability concerns yet at the same time encouraged to make major investments in grid modernization.
Grid Management Systems
Advanced Distribution Management Systems (ADMS) and Distribution Energy Resource Management Systems (DERMS) are technology and software systems that manage the utility operations and assets, promoting efficient integration of DERs and other grid modernizations. In addition to ADMS, Supervisory Control and Data Acquisition (SCADA) is a management system used to monitor and control grid operations, better integrating real-time data from the generation to distribution. These systems are primary modernization investments that allow the utilities to seek a greater degree of operational efficiency, system flexibility and new connection options for managing our changing energy landscape.
Distributed Energy Resources (DERs) and Battery Energy Storage System (BESS)
Small, localized assets, like DERs and BESS’ may provide reliability advantages and system flexibility, particularly when integrating renewables with intermittency issues into the grid. There is distinct positive trend in the demand for interaction requests in many Canadian jurisdictions, demonstrating that modernization investment will be necessary to accommodate future customer preferences. With limited investment certainty, pressure to invest in enabling technologies to connect more DERs and BESS creates further changes in managing business risk as part of grid modernization. Without sufficient grid modernization investment, the integration of these new assets at the desired scale will not be possible.
Non-Wire Alternatives (NWAs)
NWAs can optimize network operations and support more efficient use of resources over the long term, resulting in lower costs for customers. A primary challenge for utilities pursuing NWAs is the lack of investment incentives. The traditional regulatory framework for utilities establishes a reasonable expectation for recovery of operating expenses combined with low-risk investment and guaranteed returns on capital expenditure. These are fundamentals of the sector, based on the overarching regulatory principles and our understanding of what is used and useful.xviii
Used and useful principle
For an asset to enter a utility’s rate base and be eligible for a return, the asset must be used and useful to customers. The used and useful test is intended to prevent overinvesting that would inflate the rate base.
Regulators can play a crucial role in mitigating investment risks by creating clear mechanisms for evaluating and incentivizing such investments. For example, Nova Scotia has capital expenditure justification criteria which include specific measures for innovation. These evaluation metrics provide a regulatory pathway for innovation investments, aligning value assignments for customers, regulators, and utilities.
While these investments can be more cost effective than traditional asset investment, they also are not without risk. Risk arises from the lack of clarity around grid modernization evaluation. Many jurisdictions do not have clear frameworks for evaluating NWAs compared to traditional wired assets. These case-by-case assessments require a greater amount of operational effort on behalf of the utility for project planning, increasing the complexity and risk.
NWAs allow utilities to defer traditional capital expenditure. Utilities can leverage these tools to better manage existing assets and infrastructure, but they cannot be solely depended on, particularly with the expected demand increases the sector will face in the coming years.
International approaches
United Kingdom
Through risk and reward sharing mechanisms, underspends or overspends for utilities investments are distributed between the company and consumer. This provides opportunities to align utility, customer, and regulator priorities.
United States
In New York, Utilities can capitalize certain NWA expenditures, providing them with a return on investment like traditional capital projects. New York uses Earnings Adjustment Mechanisms (EAMs) to reduce investment in traditional infrastructure.
Risk reduction measures
Benefit-Cost Assessments (BCA)
Some Canadian provinces have pursued BCA frameworks. For example, the Ontario Energy Board (OEB) has developed a BCA framework to guide electricity distributors in evaluating NWAs and DERs.xix In the United States, the Department of Energy developed a national BCA methodology for grid modernization investments, to demonstrate how these investments will provide net benefits to customers.xx
These tools allow regulators and utilities to assess the full distribution-level impacts of these solutions. However, many provinces still lack clear and standardized evaluation tools for DERs and NWAs, creating heightened risk in pursuing these investments.
Rate riders and trackers are used to ensure that certain utility costs, are recovered, without the need of a general rate case for approval.
Incentive structures
Regulators must enable utilities to pursue foundational grid modernization investments by approving tailored funding mechanisms. This can be done through funding tools like specialized rate riders and variance accounts to increase revenue for dedicated grid modernization investment.
Sandboxes, which have been adopted by some provinces, can serve as an excellent tool in promoting grid modernization. But they can also be limited in scope and serve to undermine more nascent grid investments because they don’t fall under the predefined structure of the sandbox. While greater adoption of regulatory sandboxes can derisk investments in grid innovation, the presence of these sandboxes should not serve as rationale for disallowing other innovation accounts.
Regulatory sandbox is a controlled environment established by regulatory bodies that allows utilities to test innovative activities, services, and business models in real-world conditions while operating under temporarily modified regulatory requirements.
For example, while Toronto Hydro was successful in the use of the OEB’s and the IESO’s innovation funds for an NWA project, the utility was unsuccessful in their application for securing an innovation account for expenditure for more nascent innovation.xxi Regulators need to consider and provide guidance on how projects can move from the sandbox into rate applications.
Regulatory measures in grid modernization
Promote grid modernization expenditure through incentive mechanisms
\ Clear policy guidance from regulators to enable grid modernization to achieve government and regulatory priorities: Regulatory priorities and investment direction for utilities should recognize that grid modernization is required to achieve policy goals. Clear policy guidance from regulators should be provided to utilities on how to achieve key governmental and regulatory directives through grid modernization.
\ Approve investment plans and offer targeted funding mechanisms: Regulators must support utilities to pursue foundational grid modernization investments approving investment plans and offer targeted funding mechanisms. Regulators can enable utilities to pursue grid modernization investment by approving tailored funding mechanism like rate riders and variance accounts.
Standardize assessment frameworks to increase certainty around investment
Recommendations:
\ Use robust Benefit Cost Assessments (BCAs) and complementary policy frameworks to provide greater certainty for Non-Wire Alternative investments: Frameworks and tools that standardize assessments for grid modernization investment reduce the risk of expenditure and reduces uncertainty. BCAs are an important tool in assessing the value of grid modernization investments and allows for comparisons to traditional alternatives. Using BCAs increases confidence around rate submissions, reduces risk, and supports efficient, data-driven decisions, creating clear value for the customer.
\ Optimize investments in Non-Wire Alternatives (NWAs) by allowing relevant operational expenditures incentive payments: By allowing some degree of strategic operational expenditure to receive a rate of return or equivalent incentive, utilities can be better incentivized to invest in these kinds of grid modernization. Implementing mechanisms that monetize the benefits of modernization can help reduce investment risk for utilities.
Accommodate a greater degree of novel innovation expenditure
Recommendations:
\ Implement an innovation sandbox with sufficient financial support: Innovation expenditure is an essential part of grid modernization, but it is not effectively supported and incentivised in our regulatory system. While the sandbox structure has shown to be effective, the degree of funding associated with this model is often too low to enable the viability of major grid modernization projects. Implementing an innovation sandbox with sufficient financial support would substantially reduce the risk of investment.
\ Approve individual utility innovation accounts funded through the rate base: The use of individual utility innovation accounts can help fill this funding gap and be a tool to support novel projects. In some jurisdictions the parameters of eligible expenditure for innovation funds, may be directed towards innovation with a high certainty of viability, thus missing some critical areas for utility innovation. Approving individual utility innovation accounts funded through the rate base can complement existing innovation incentives. Enabling Innovation expenditure can yield major returns in efficiency, creating value for the customer.
Climate adaptation
Climate related risk is an ever-growing concern for utilities, particularly as service providers are looking to substantially invest in assets and systems to manage load growth and grid modernization needs. As generation, transmission, and distribution assets expand, disruptions from major climate threats are having an even greater effect on reliability. The increased threat of severe weather and wildfires is creating heightened risk for utility asset management and for ensuring energy security and resiliency. Climate adaptation must be understood within the broader context of challenges, as utilities address competing priorities with limited budgets.
Regulators should consider these priorities and be prepared to provide guidance on how to approach these trade-offs, when pursuing climate adaptation investment. Climate change adaptation must be prioritized to reduce businesses risks related to reliability, liability claims, insurance premiums, and affordability.
\ Wildfires, hurricanes, heatwaves, and storms have all affected Canadians in recent years, leading to widespread impacts on electrical grids. Extreme weather events have increased about 4.5% annually.xxii
\ Canadian utilities are investing a more significant share of capital expenditures in preventive weather-hardening measures.
\ Reducing utility exposure to climate risk involves embracing modernized management practices but also increased investment in the systems and hard assets that ensure resiliency through extreme weather events.
\ Proactive adaptation strategies have been shown to reduce maintenance and renewal costs of public infrastructure.xxiii
The cost and benefits of climate adaptation must also be quantified so that utilities and regulators understand the value of climate adaptation investments in clear financial terms. Quantifying risk and the return on investment in resiliency helps direct expenditure and expedite regulatory evaluation. The cost of catastrophic insurable losses has risen substantially over last 15 years.xxiv Despite broader government initiatives to reduce the impact of severe weather events and wildfires, utilities must continue to invest to ensure reliable service through these continuing impacts. Regulators can implement strategies and tools to support utilities in managing this investment risk and reduce the impact of broader climate risk.
Wildfires
Wildfires are becoming an ever-increasing challenge for our electrical transmission and distribution systems. In Canada, the wildfire season is, lasting longer and fires are becoming harder to contain.xxv Electricity disruptions resulting from forest fires are a major threat to energy security. Proactive measures will help utilities prevent wildfires from igniting and protect their assets from damage or destruction, but achieving this level of protection requires resiliency investments.xxvi
Ensuring energy reliability in the face of increasing wildfire risk is an essential consideration for both utilities and regulators when conducting system planning, as unmanaged exposure to this risk leads to a less affordable and less reliable energy system.
Natural Resources Canada’s wildfire strategy has identified the importance of whole-of-society approach when addressing wildfire risk. xxvii
Regulators play a key role in wildfire risk management for utilities, as the federal strategy emphasizes the importance of modernizing governance structures for wildfire management. Regulators must understand that for utilities to effectively manage this risk, it requires a greater degree of investment in a variety of assets and strategies. Wildfire risk management must be integrated into utility asset management, considering interior and exterior risk impacts. Utilities are pursuing increased integration of wildfire management into the overall asset management system to support appropriate infrastructure monitoring, maintenance, and improvement activities.
Extreme storms and flooding
Extreme storms and flooding pose significant challenges to Canada’s electricity system by disrupting power delivery, damaging infrastructure, and straining emergency response efforts. High winds, ice storms, and heavy snow and rainfall, result in widespread outages and significant damage to powerlines, poles, transformers, and substations. Rural and remote areas often face prolonged outages due to difficult access for repair crews, while urban areas can experience cascading failures due to the interconnected nature of the grid. These disruptions result in significant economic losses, public safety risks, and operational challenges for utilities, including mobilizing repair crews, managing grid stability, and maintaining effective communication with customers. Damage costs resulting from these storms often exceed the storm recovery funding envelopes that utilities receive through traditional rate requests. The increased risk of climate related disruption has a series impact on the overall business risk of utilities, as resiliency expenditure and cost recovery pose recouping challenges.
Fiona’s impact on Nova Scotia
Hurricane Fiona resulted in nearly $35 Million in damages to Nova Scotia Power’s assets and equipment. This was more than three times the storm operating cost received through the rate base. Nova Scotia Power will recover the difference over a 10-year period, but political interveners posed that the board needed to “judiciously weigh” concerns that electricity company didn’t efficiently mitigate storm-recovery costs. These political challenges to recovery costs compound risk associated with resiliency investment.
Evaluation and cost recovery
Value assessments
Value Assessments are especially important in the context of climate adaptation as they help utilities prioritize investments in climate-resilient infrastructure by identifying the most economically critical areas. Utilities can use Value of Lost Load (VOLL), or a similar assessment of value for customer interruptions, to evaluate the cost-effectiveness of climate adaptation strategies, such as undergrounding powerlines, strengthening grid infrastructure, or enhancing vegetation management. The VOLL metric can be integrated into a broader BCA framework and used as a nonadjudicative tool to inform rate filings and investment planning. Utilities must evolve their planning and investment frameworks to capture climate risk, the value of customer interruptions, and customer’s willingness to pay.
Several provinces include VOLL metrics in into cost evaluation and others are pursuing more formal frameworks as part of reliability assessments. For example, the OEB is currently conducting a Vulnerability Assessment and System Hardening Project (VASH) to develop a VOLL methodology to be included in distribution system planning processes.xxviii
Value of Lost Load (VOLL) is a key metric for climate resiliency and disruption cost evaluations, as the metric quantifies the economic and societal cost of electricity outages. It reflects the value that customers place on uninterrupted power supply and aids service providers and regulators in managing affordability concerns while still maintaining reliability investments.
Additionally, as part of a reliability plan to strengthen grid resilience, the Nova Scotia Utility and Review Board (NSURB) outlined the benefits of evaluating the VOLL by customer class to support investment decisions.xxix These evaluation tools provide certainty around investment in infrastructure that reduces the exposure of utility assets to climate risk.
Insurance, investment and cost recovery
Canadian jurisdictions take varied approaches to reliability expenditure, and the cost recovery mechanisms used after climate related damages. Transmission and distribution operators have been able to ensure a high degree of reliability due to the investments made in system management and hard assets. But as affordability concerns rise and politics and
public policy have a more active impact on the utility investment outlook, regulators have raised concerns about over investment in reliability.
This balancing of reliability and affordability is a serious concern for utilities. Service providers understand the affordability constraints of their customer base but also consider the long-term risks of lowered investment in reliability. Most jurisdictions collect storm and wildfire response expenditure as part of the general rate base, but incidences over the past few years have shown that these revenues collected fall short of what is needed. To make up the difference in response expenditure, and to ensure that storm and wildfire accounts don’t become bloated in years of low activity, mechanisms like rate riders are implemented to recover response costs. In the long-term, consistent investments in reliability are necessary for mitigating the risk of climatic threats. This helps ensure response costs are not recouped at a time where the customer is more sensitive to affordability concerns, after significant storm or wildfire related damage has occurred.
Disaster funds and deferral accounts: Provincially supported funds and accounts can serve as insurance options provided by provincial governments and regulators, as a place to store funds in case of severe weather or wildfire damage. Government funds can be directed to these accounts over a scheduled period, where upon utilities can request funding to reduce the impact of replacement costs when capital assets are destroyed. Funding for these accounts can come from direct government allocation or utilities may use a rate integration method that builds the expected cost of damage into the rate base.
Regulatory measures in climate adaptation
Support resiliency though long-term strategic investment priorities
Recommendations:
\ Ensure hard asset and operational climate management expenditure is at an effective level: Resiliency investment is essential to reducing utility exposure to increasing climate risk. Grid hardening allows service providers to better manage storms, flooding, and wildfires. To reduce climate impact on investment, risk regulators should be prepared to approve increased hard asset and operational climate management expenditure.
\ Mediate affordability concerns with long term risk evaluation: While grid hardening investments must be moderated by affordability concerns, the importance of resiliency expenditure can not be downplayed for short term affordability pressures, as it is in the best interest of the consumer to ensure resiliency is adequality funded. Regulators need to mediate affordability concerns with long term risk evaluation.
Support sufficient cost recovery measures
Recommendations:
\ Establish sufficient climate recovery funds based on forward looking climate plans: After climate related damage has occurred it is an imperative that utilities re-establish disrupted service as quickly as possible. This requires utilities having access to sufficient funding for rapid response times. Many jurisdictions already have climate response funds baked in the rate base, but they often fail to cover total damage cost. Establishing sufficient climate recovery funds based on forward looking climate plans is essential to reduce the business risk utilities face in the wake of major damages.
\ Efficiently approve of climate related cost overruns to be included in the rate base: Utilities working to restore power after major events often spend more than the typical event response fund. Ensuring that the total cost of damage is recouped is essential for maintaining long term viability of the service provider. The approval of climate related cost overruns included in the rate should be efficient and without undo external pressure from interveners. To ensure effective power restoration for customers, utilities must know that they can recoup costs efficiently.
Evaluation and management frameworks that promote data driven investments
Recommendations:
\ Implementing a Value of Lost Load (VOLL) framework can serve as an effective tool to justify expenditure: A challenge of resiliency investments and grid hardening is knowing when investments yield diminished returns in risk reduction. Having consistent evaluation frameworks that operate outside adjudicative hearings gives service operators the ability to accurately assess the cost to benefit ratio of increased resiliency investment.
\ Implement climate adaptation management plans that use a consistent approach across the sector: This creates a streamlined approach to information and best practices sharing. Increasing the access utilities have to effective data, evaluation frameworks, and successful management practices decreases the risk and uncertainty in climate adaptation investment.
Conclusion
The investment decisions facing electric utilities and regulators are multifaceted and interconnected across load growth, grid modernization, and climate adaptation. Load growth, driven by increased electrification of homes, transportation, and industry, creates significant uncertainty around forecasting and planning, thereby heightening investment risks. Grid modernization introduces further complexity, as utilities must integrate advanced technologies and operations into existing systems. And increased climate risk further impacts broad investment risk, as severe weather events, wildfires, and flooding require investment in infrastructure reliability and increase operational costs. Utilities are facing policy pressure and affordability concerns, however, are encouraged to make major investments in the grid. This balancing of investment and customer value is a serious concern for utilities, as they are faced with a changing energy landscape.
Regulatory bodies can improve infrastructure investment for customers through policy integration and regulatory reform. Regulatory mechanisms such as variance accounts, mid-project cost recovery, and clear Benefit-Cost Assessment (BCA) frameworks increase certainty around investment planning. Additionally, regulatory sandboxes and innovation funds can de-risk innovation expenditure, and standardized evaluation frameworks for modernization investments provide clarity and consistency in investment decisions.
Integrating policy impacts into regulatory decisions ensures alignment between government mandates and utility investment. Robust climate adaptation strategies, including Value of Lost Load (VOLL) frameworks and sufficient cost recovery mechanisms, are crucial in safeguarding infrastructure against climate-related disruptions. These regulatory innovations can create a more adaptable and financially sustainable system for utilities navigating Canada’s evolving energy landscape, reducing the investment risk associated with our key challenges and ultimately bringing greater value to customers.
Endnotes
i End Use Demand, Canada Energy Regulator (Visual Created by the Electricity Canada), 2024
ii Updated Demand Forecast, IESO, 2024
iii 2024 Long-Term Outlook, AESO, 2024
iv Electricity Demand Press Release, Hydro-Québec, 2024
v Powering Our Future: BC’s Clean Energy Strategy, Government of British Columbia , 2024
vi Updated Demand Forecast, IESO, 2024
vii 2024 Long-Term Outlook, AESO, 2024
viii Manitoba Affordable Energy Plan, Government of Manitoba , 2024
ix Canada Data Centers, Data Center Map, April 2025
x AI-powered data centres to push Ontario’s energy demand to new heights, The Trillium, 2024
xi Market Snapshot: Energy demand from data centers is steadily increasing, and AI development is a significant factor, Canada Energy Regulator, 2024
xii Bill 10 - An Act to Amend the Electricity Act, Government of New Brunswick, 2023
xiii Bill 69: A new era for the Québec energy sector, BLG, 2024
xiv Waves of Change, Indigenous Clean Energy, 2022
xv Navigating Barriers to Utility Investment in Grid Modernization, Guidehouse Canada for Natural Resources Canada , 2020
xvi Solving Gird-Lock, Electricity Distributors Association, 2024
xvii Manitoba Affordable Energy Plan, Government of Manitoba , 2024
xviii Back to Bonbright, Electricity Canada , 2023
xix Benefit-Cost Analysis Framework for Addressing Electricity System Needs, Ontario Energy Board, 2023
xx Benefit-Cost Analysis for Utility-Facing Grid Modernization Investments: Trends, Challenges, and Considerations, U.S. Department of Energy, 2021
xxi Decision on Toronto Hydro’s Proposed Innovation Fund, Ontario Energy Board, 2024
xxii Always On, Electricity Canada , 2024
xxiii CIPI: Summary Report – Estimating the budgetary impacts of changing climate hazards on public infrastructure in Ontario, Financial Accountability Office of Ontario, 2023
xxiv Integrating Physical Climate Change Risk Into Investing, Intact Center on Climate Adaptation, 2023
xxv Canada’s record-breaking wildfires in 2023: A fiery wake-up call, Natural Resources Canada , 2023
xxvi 2024 Wildfire Risk Management Framework, Electricity Canada , 2024
xxvii Forest fires, Natural Resources Canada , April 2024
xxviii Vulnerability Assessment & System Hardening Project, Ontario Energy Board, 2024
xxix Five-Year Reliability Plan 2025-2029, Nova Scotia Power, 2024
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