Governance and accountability

Governance and accountability

Introduction: Delinieating responsibilities

Clear policy direction, a commitment to achieving a clean energy economy and integrated, long-term energy planning will illuminate the potential pathways for Ontario’s energy future. To operationalize this, the province will require a robust system of governance and accountability that promotes and facilitates alignment among government, social and economic forces required to bring about the energy transition.

Ontario’s energy governance entities must show thought leadership and embrace the challenges and opportunities of electrification and the energy transition. The objective should be a system of governance and accountability that unlocks potential, enables innovation, fosters investment and encourages experimentation and reasonable risk-taking. Such a system will enable private actors to make innovative investments that are aligned with the clean energy economy objective, while protecting consumers, maintaining affordability and bolstering reliability.

To support electrification and the energy transition, the province will need to embrace a regulatory framework that encourages innovation and actively supports the project of decarbonization. Ontario will need a technical planning regime that can move independently but is held accountable by effective oversight. It will need to align governance of the natural gas sector with government’s clean energy economy policy objectives in a manner that maintains affordability, reliability and protects customers. And it will need to support experimentation and evolution in business models that deliver energy solutions. Bolstering the existing framework of governance and accountability so that it can meet the challenges ahead will be crucial to capturing Ontario’s opportunity in this strategic moment.

Enabling innovation and experimentation

Electrification and the energy transition are driving significant innovation in energy technologies and in solutions for their deployment and management. Further innovation is required to fully achieve a clean energy economy. This will necessitate a regulatory environment that encourages innovation and experimentation and embraces change.

In many ways, existing energy regulatory regimes are ill-equipped to deal with rapid innovation. They were established and designed to govern highly centralized energy systems. New technologies are challenging these traditional structures and opening up technical possibilities that did not exist when regulatory systems were first established. The advent of bidirectional flow, for example, challenges a regulatory system designed under the assumption that electricity flows only in one direction – from large generators to the consumer. Distributed Energy Resources (DERs) have altered how customers interact with the grid, creating “prosumers” who can both produce and consume electricity and actively provide grid services, not just consume them. Storage and the notion of using Electric Vehicles (EVs) as mobile storage units create new complexities in the management and pricing of energy. These new technical capabilities raise a myriad of challenges concerning not only the physical management of the energy system, but also pricing and the entry of non-traditional market participants. The new era of energy is one in which regulation will need to be flexible, forward-looking and able to cope with technological and market uncertainty.

The Panel heard that there is a need for agency mandates that support greater consideration of and support for innovative technologies and solutions. The frameworks and entities charged with regulating and planning the system can support innovative solutions in many different ways. At base, providing a fair and level playing field for new and emerging solutions to compete with incumbent players can open doors for cost-effective innovations that could accelerate electrification and the energy transition. Not pursuing necessary reforms would deprive Ontario of cost-effective energy supply and management options that have the potential to significantly lower costs, accelerate movement toward the clean energy economy and enable further innovation.

Some stakeholders pointed to the Ontario Energy Board’s (OEB’s) Innovation Sandbox, which provides regulatory space for testing new activities, services and business models in Ontario’s electricity and natural gas sectors, as an excellent model for encouraging innovation and learning, providing fast regulatory feedback and enabling reasonable risk taking by both solution providers and the regulator tasked with protecting customers. Many jurisdictions, primarily in Europe, have implemented similar programs. Belgium, France, Germany, Italy and the Netherlands have developed innovation sandbox programs for the energy sector to accelerate innovation in technologies, services and business models, particularly those which support decarbonization.

The United Kingdom’s (UK’s) Office of Gas and Electricity Markets (Ofgem), the energy regulator for Great Britain, developed an internal program known as Innovation Link, which supports innovation and experimentation, particularly in the retail energy market for low carbon products and services that directly benefit consumers. The program does this by guiding innovators through how the regulatory system may impact their proposed project and whether it may face regulatory barriers. Innovation Link can provide temporary derogations from various regulations and codes to support the development and testing of an innovative solution. The program has assisted in the development of energy solutions such as peer-to-peer energy trading, demand response with smart storage heaters and residential solar and storage.

Singapore’s Energy Market Authority is similarly empowered to create regulations and apply exemptions to codes of practice, market rules and licensing conditions to support experimentation with innovative energy solutions. This flexible policy tool allows industry proponents to test new products and services while protecting consumers and also provides the regulator with an opportunity to frequently review how existing regulations might constrict emerging solutions.

Recent amendments to the Ontario Energy Board Act have provided the OEB with the power to make orders that temporarily waive certain licensing requirements for innovative pilots or demonstration projects to facilitate innovation in the energy sector. This is the kind of experimentation and reasonable risk-taking that can encourage and kickstart innovative energy solutions and is an encouraging sign that the province is committed to supporting and facilitating innovation.

An innovation sandbox (or similar policy tool) can help remove non-technological barriers to innovation and encourage learning-by-doing while protecting consumers. This in turn can create a more favourable environment for the development and scaling of innovative energy solutions that can support electrification and the energy transition. A review of Ofgem’s Innovation Link, for example, demonstrated that start-ups with innovative energy solutions used Innovation Link applications to signal to investors that their innovation faced no regulatory barriers.

Special attention should be given to enabling innovative partnerships and collaboration with Indigenous partners. The government recently increased funding for the Independent Electricity System Operator (IESO) to support Indigenous leadership and capacity in the electricity sector through the Indigenous Energy Support Programs. Encouraging and supporting innovation with Indigenous partners is an important part of ensuring communities can benefit from the energy transition.

Besides direct regulatory support for experimentation, the Panel heard that innovative market structures, incentives, and utility business models can be enablers of electrification and the energy transition. Stakeholders expressed support for the continued exploration of new business models and the broad diffusion of learning and results, where applicable.

Stakeholders made it clear during the engagements that while pilots are important in providing benefits for the Ontario system and for technology developers wanting to demonstrate their technology for deployment elsewhere, they are only a first step. It is crucial to move beyond pilots to broad adoption in order to unlock the full potential of new technologies and business models. To that end, IESO and OEB should regularly report on how specific pilots can be the basis for broad adoption, what legislative or regulatory changes would be needed, and what regulatory requirements that are sometimes suspended during trials need to be put in place for protecting customers and maintaining a competitive environment.

While supporting these innovative technologies and business models, it is critical that the principal aim of customer protection is maintained. Electrification and the energy transition are likely to require a significant amount of technological change, including alterations and installations at the customer level. Installing electric vehicle chargers, deploying DERs, implementing storage solutions and other alterations will need to be done safely. Licensing, distribution, product safety, electrical code and compliance enforcement play an important role in enabling innovation and in ensuring customer trust and buy-in to new technologies. Safety and technical consistency therefore need to remain a priority

Recommendation 10: To enable the effective evolution of innovative business models in line with clean energy economy goals and to help consumers benefit from electrification and the energy transition, the OEB and IESO should:

1. Continue encouraging experimentation by utilities, innovators, and new market entrants through platforms, such as the Grid Innovation Fund and the Innovation Sandbox program and ensure appropriate resourcing of these programs
2. Regularly evaluate and build on these initiatives to advance successful projects beyond the pilot stage to broader adoption when appropriate, proactively identify any legislative and regulatory barriers to government, and ensure sustainable business models
3. Review opportunities to help consumers through electrification and the energy transition, including business model innovations that provide new products and services that enable consumers to finance the high up-front capital costs for building retrofits and fuel-switching appliances in a fair and affordable manner

Recommendation 11: Safety regulators and technical standards organizations must be included in energy planning and energy sector regulation to enable proactive coordination and the effective deployment of new technical solutions.

For example: The Electrical Safety Authority (ESA) and the Technical Standards and Safety Authority (TSSA) play critical roles in product approvals, reviewing plans for new facilities and installations, customer and industry education regarding electrical safety, and, in particular, monitoring, assessing and responding to any emerging public safety risks from electrification and the energy transition (for example, regarding integration/installation of energy storage and vehicle-to-grid installation into homes and buildings)

Adaptability and flexibility for the energy transition

In the context of the energy transition, energy regulators are increasingly being asked to address a broader range of outcomes beyond price, cost, reliability and quality of service. To bring about alignment with government priorities, many jurisdictions have empowered their regulators with a specific mandate to pursue – or at least consider in decision-making – objectives and targets related to climate change and decarbonization.

The UK’s Ofgem, for example, has been specifically mandated by the UK Parliament to work with government, industry and consumer groups “to deliver a net-zero economy, at the lowest cost to consumers” as one of its three core responsibilities. Ofgem’s strategic vision includes putting the UK’s energy system “on track for net-zero" and supporting the development of “an electricity sector able to function without fossil fuels, with a growing share of low-cost renewables, alongside the development and deployment of other sources of low carbon power.” California’s Public Utilities Commission (CPUC) was directed by the Governor to accelerate the state’s progress toward its climate goals. New York’s Department of Public Service has a mandate that includes ensuring the preservation of environmental values and the conservation of natural resources. Stakeholders also pointed to Maryland, Colorado, Maine, Massachusetts, Washington, Hawaii and Washington D.C. as jurisdictions that have passed legislation mandating consideration of climate change in regulatory decisions. These examples are all slightly different, but they all provide examples of how energy regulators are increasingly incorporating objectives and targets of electrification and energy transition into their mandates and core values. That said, all jurisdictions are still very early on this path and there remains much to learn about how best to incorporate clean economy goals into economic regulation.

Stakeholders agreed that a clean energy economy target and supporting policy direction can help guide regulatory agencies, inform decision-making and goal setting and create forward momentum. Setting parameters for measuring success would be critical in meeting any target. As a corollary, some stakeholders suggested that the OEB’s mandate could be expanded to specifically include emissions reduction or net zero objectives to enable the OEB to take a more holistic view of sector regulation when setting “just and reasonable rates” and provide greater clarity and predictability for the sector. Other stakeholders disagreed, arguing that a net zero target is too arbitrary for the OEB to operationalize, and that government should first develop a detailed and comprehensive strategy. Stakeholders suggested that the IESO and the OEB should be required to report regularly on the progress of decarbonization efforts in both the electricity and natural gas sectors.

Indigenous partners raised as an important accountability commitment to prioritize long-term relationship building, such as collaborating with Indigenous communities on a definition of success that considers Indigenous partners’ immediate, medium and long-term goals. Actions to support greater accountability and transparency throughout the transition include facilitating ongoing dialogue and collaboration with Indigenous partners regarding anticipated costs and impacts of the transition and demonstrating how Indigenous perspectives have informed accountability processes and the development of key performance metrics.

The Alberta Utilities Commission (AUC) produces an annual report card that tracks quantitative indicators of progress against government’s strategic objectives in the regulation of the energy sector. While the AUC does not track progress on electrification and energy transition targets, it is nevertheless an example of how quantitative measures can support the tracking of movement on strategic objectives in the sector.

The OEB’s submission to the Panel highlighted specific amendments that might empower the OEB to be a more proactive agent in advancing electrification and the energy transition. For example, there may be an opportunity to add new language to the OEB’s authority related to electricity transmission leave-to-construct applications as a means of clarifying that the OEB can consider government policy related to emissions reduction and the clean energy economy in assessing whether a transmission project is in the public interest. Additionally, the Panel heard that there may be merit in broadening the OEB’s powers with respect to natural gas to ensure it has a broader basis on which to protect natural gas customers during the energy transition.

The Panel feels strongly that the OEB’s existing objectives and associated mandate are sufficient for the moment. As electrification and the energy transition progress, it may become necessary to provide the OEB with additional objectives, authority or functions in order to ensure it is able to effectively regulate the evolving energy sector and support the province’s clean energy economy goal. Across Canada and internationally, the integration of climate objectives into economic regulation is in its very early stages. A review in the future will also enable learnings from other jurisdictions to be incorporated into potential changes to the OEB. The single clearest imperative is the need for adaptability and flexibility as the energy sector undergoes this significant transformation.

The Boards of Directors of IESO and OEB will have a crucial role in overseeing the energy transition, both in terms of technical and cultural change. The Boards play an important role in risk management particularly, overseeing the pace of the transition for their respective organizations to ensure they are best resourced to meet immediate needs as well as in a position to deploy resources for evolving needs. Ongoing and proactive and appropriate communication between Board members and the Ministry will better ensure risks are identified and managed. Appointments to the Boards of these organizations should be conducted with a view to building the current and emerging skillsets and competencies needed to successfully guide organizations through these changes

Recommendation 12: The OEB should employ all tools within its existing mandate to implement activities consistent with the Province’s goals for a clean energy economy and the requirements of the energy transition for Ontario.

The OEB should enhance risk-based approaches to regulatory oversight, consistent with best practice. This would enable more agency resources to be focused on emerging energy areas and economize on traditional regulation.

Recommendation 13: In the years following release of the energy transition policy vision, the province should undertake a review of the OEB’s activities in respect of achieving objectives within the policy vision to determine if potential legislative and/or regulatory changes are needed to implement the vision effectively. These potential changes could include:

1. Updating the OEB’s policy, mandate, and/or objectives to reflect the clean energy economy transition, including addressing greenhouse gas (“GHG”) emission reductions
2. Including GHG emissions as an additional factor for the OEB to consider in proceedings, such as transmission leave-to construct applications
3. Revising objectives related to the natural gas sector to align with government policy direction on the long-term role of the sector
4. Reviewing other aspects of the OEB’s objectives and legislation as it relates to facilitating the clean energy economy, for example amending the definition of “gas” to include hydrogen blending, if deemed necessary

Independent, agency-led technical planning

The management and development of energy systems requires both high-level policy direction and planning (discussed in Section 5) as well technical planning. Technical planning is the ongoing process of evaluating the capability of the energy system to meet demand and determining the appropriate mix of resources and infrastructure required to meet future needs. In Ontario’s electricity system, technical planning includes bulk system planning (led by the IESO), regional planning (led by IESO and transmitters with local distribution companies (LDCs)), and distribution sector planning (led by LDCs). The Ministry of Energy has historically provided this policy direction to the sector in a number of ways, including prescriptive ministerial and supply mix directives, and broader, higher-level policy plans (Long-Term Energy Plans).

The Panel heard that technical energy planning should be disentangled from political direction as much as possible. Stakeholders generally agreed that, while government should provide overall planning direction about policy objectives, design specifics should be left to the IESO. Stakeholders called for the IESO to be empowered with the necessary tools, mandate and independence for reliable clean energy grid planning and procurement, and the flexibility to plan for various electrification scenarios, account for potential demand impacts and procure the required electricity supply. The 2021 Long-Term Energy Planning Reform engagement yielded very similar feedback. Stakeholders noted the IESO’s technical expertise and were supportive of its continued role as the ‘expert planner.’

The Panel agrees that equipped with broad policy direction, clear policy objectives and guiding principles from government, the technical planning of the electricity system is best conducted by independent agencies. Technical expertise is required to properly evaluate the capabilities of the electricity system, determine the appropriate mix of resources and infrastructure required to meet future needs and execute procurement processes.

The Panel also heard that while efforts to build capacity take time, in order to increase Indigenous communities’ technical energy and systems knowledge, government and the sector must create space for Indigenous perspectives throughout energy and technical planning discussions.

The Panel also heard that the OEB is best suited to take a lead role in oversight and review of coordinated energy planning and procurement. Stakeholders called for the OEB to review IESO planning activities to ensure they align with the government’s overall direction and are cost-effective. This feedback again echoes that of stakeholders from the Ministry’s 2021 Long-Term Energy Planning Reform engagement. On that occasion, stakeholders called for oversight mechanisms to be established to monitor the development of policy direction for and implementation of energy planning, in the interest of enhancing the transparency and accountability of planning processes and decisions. An OEB review process would be an addition to existing accountability and review mechanisms currently operating in the procurement and planning space. The IESO employs Fairness Advisors tasked with ensuring that it is in compliance with the relevant procurement processes and laws and to ensure that all potential proponents are treated consistently and fairly. The OEB also operates the Market Surveillance Panel, which is tasked with identifying inappropriate or anomalous conduct by market participants, identifying activities of the IESO that may have an impact on market efficiencies or effective competition, and identifying any actual or potential flaws and inefficiencies in the market rules or the structure of the IESO-administered markets.

The Panel feels strongly that OEB review should be a retrospective, post hoc regularized review of the overall planning process to provide guidance on future planning and procurement, not a review of individual procurements. This will ensure timely decisions can be made. It will increase transparency while avoiding uncertainty for project proponents and investors. The focus of such a review should be to improve future planning and procurement and ensure its alignment with the government’s stated policy objectives and guiding principles.

Recommendation 14: In line with input received during the 2021 review of Ontario’s long-term planning framework, IESO should be empowered, within the broad direction established by government, to independently procure electricity resources and lead bulk-system planning (including potential use of interties) and regional electricity system planning. The OEB should provide regular procedural review of IESO-led planning and procurement, to be set out in legislation.

Technical planning for natural gas

One of the core challenges in governing and regulating electrification and the energy transition will be maintaining clear accountability and consumer protection in the natural gas system in the face of shifting customer values and preferences and the overall shift to a clean energy economy. Natural gas has long played an important role in the energy system of Ontario, as a source of power for electricity generation, as a fuel for home heating and cooking and as a feedstock and source of process heat for industry. It is clear that natural gas will continue to play these critical roles in the short- to medium-term. Longer-term prospects, particularly for home heating, are less clear. As discussed in Section 5, emerging evidence shows that it is unlikely the natural gas system can be fully decarbonized and continue to deliver cost-effective building heat. The development of regulatory frameworks and the evolution of natural gas infrastructure will need to align with the province’s overarching clean energy economy commitment and protect customers as the role of natural gas changes in the province. A failure to align these regulatory frameworks with government’s overarching policy commitments could result in significant cost hazards for customers or threats to overarching government policy commitments and an effective, orderly and well-aligned transition to a clean energy economy.

Protecting customers through the transition

There is increasing evidence that electrification of building heating may become the more cost-effective option over time. The speed at which customers would change their heating source is uncertain and dependent on a large number of individual factors, such as equipment age and personal preferences and values, as well as system-level and policy factors, such as cost development, availability of equipment and qualified technicians, and supportive policies and incentives. Nonetheless, this could lead to many customers disconnecting from the natural gas system absent any personal motivation to lower their carbon footprint. As a result, there is a real risk of stranding assets in home heating and the gas distribution grid over the medium to long-term, with significant risk to customers, investors and public finances. As more customers exit the natural gas grid to adopt electric heating, those customers who are least able to afford to electrify could be forced to pay higher and higher proportions of the network cost to keep the system running safely.

Other jurisdictions are also grappling with these difficult policy challenges. A report on long-term gas utility planning prepared for the Colorado Energy Office in 2021 highlighted the potential cost hazards posed by traditional cost of service regulation in a future characterized by large-scale defection from natural gas heating. Those customers who can afford the higher upfront costs of heating electrification will be the first to defect from the gas system, and without regulatory changes, the remaining customers (who will tend to be lower income) could be left to shoulder the cost for the remaining gas system. Similarly, the final report of the Massachusetts Commission on Clean Heat highlighted how, as the state transitions to predominantly electrified building heat in the long-term, natural gas rates could go up significantly as fewer households support the system’s fixed infrastructure costs. The report highlighted this hazard as an equity concern, noting that Massachusetts needed to ensure that low- and middle-income households are adequately assisted and prioritized such that they do not disproportionately bear remaining gas infrastructure costs.

Perhaps most importantly, both the Colorado and Massachusetts reports highlighted the need to consider the cost hazards of asset depreciation, regulated returns and mass grid defection in planning for natural gas system upgrades and expressions. The Massachusetts Commission on Clean Heat emphasizes that the state should avoid future investments in gas pipeline infrastructure that will disproportionately burden low- and middle-income households. The report for the Colorado Energy Office stated that the hazards of stranded assets and cost recovery should be addressed “at the level of the strategic framework” and that steps should be taken now to optimize gas system investments – using a full accounting of lifetime costs – to mitigate stranded asset risk and cost burden in the future.

Considerations like these are being incorporated into regulatory decision-making. The state of New York’s Public Service Commission (PSC) is requiring planning by utilities to align with state climate goals and reflect electrification mandates and the development of scenarios to understand cost developments so that assets can be fully depreciated and are not stranded as the customer base shrinks. The cost hazards of large-scale grid disconnection were highlighted by an expert intervenor testimony on a rate application from a large gas utility in 2022. In that case the expert witness testified that the utility’s plans would leave billions of dollars of assets at risk of stranding in 2050, when pipeline throughput will be much lower given emissions reduction requirements. Given the state’s policy objectives of decarbonization and electrification, and assuming a rate of departure from the natural gas system in line with the Commission’s gas planning order, the expert witness’ modeling indicated that average annual household gas delivery bills could more than triple by 2050 to support the system and cost recovery. These effects could in turn push more customers to exit the gas grid. As gas rates increase, the economics of electrification become more favourable for customers, and as each additional household electrifies or otherwise substantially reduces their use of pipeline gas, more rate pressure is added on remaining customers, perpetuating a vicious cycle. The witness stated that this risk could be mitigated, and thus costs avoided, by reducing the scope and scale of the pipeline enhancement or by shortening the depreciation lifetimes for new assets to align with their expected utilization timeframes.

Each of these cases is shaped by the unique market and regulatory characteristics of the jurisdiction, but the basic conundrum is a general one. A submission to the (OEB) on behalf of the Industrial Gas Users Association (IGUA) filed in August 2023 identified the same issues and advocated that decisions about the funding, utilization and maintenance of gas system assets be made at a system level in planning frameworks. In the rate case currently before OEB Commissioners, staff submitted that the revenue horizon for an economic feasibility assessment should be shortened from 40 years to 20 years, with implications for higher contributions in aid of capital. Staff also submitted that the natural gas utility should be required to provide more information and analysis on energy transition assumptions in load forecast and include forecast risk and stranded asset risk in its cost-benefit methodology for integrated resource planning. This issue will require careful governance intervention to ensure a well-managed transition that maintains affordability and protects customers.

It is quite possible that customers will withdraw from the natural gas grid at a different and much slower pace than the one outlined above. This alternative scenario could involve a plausible future with a significant emphasis on hybrid heat - using heat pumps and natural gas furnaces and boilers - rather than a full switch to heat pumps. In that case, the volume of gas sent through the natural gas distribution grid would decrease substantially, but the ongoing fixed costs to maintain the grid would continue to be split among a large and largely stable number of customers.

In either case, it is in the interest of the province, for the purpose of customer protection, to ensure that the regulatory mechanisms for the governance of the natural gas grid are aligned with a range of plausible outcomes, notably those that pose the greatest risks to customers. Other contextual risk factors should also be considered, such as societal, economic, or technological trends that may have an impact on future natural gas demand. Careful consideration of asset lifetimes, contingency planning for infrastructure expansion and enhancement proposals and stress-testing cost allocation mechanisms will be crucially important should a high-defection scenario come to pass. And such steps will not threaten the cost-effectiveness of the natural gas system in a scenario of prolonged reliance on the natural gas grid.

It will be critical, in the interest of customer protection, to further develop the province’s regulatory framework so that it is prepared for a range of possible outcomes and that in so doing, it can contribute to Ontario’s clean energy economy goal. The use of scenarios in the development of corporate strategy as well as regulatory decisions and government policy will enable Ontario to be prepared for a range of possible paths, driven by government policy, technological developments, market realities, and customer actions. Scenario-based analysis can also contribute to an open and transparent debate about opportunities and risks in the energy transition.

A framework for gas-electric coordination

In the past, different energy demand applications were fairly closely associated with specific energy sources. The increase in electrification options, not just building heating discussed above but also transportation, steel making and others, means that customers now have options regarding the energy source they want to use to satisfy a certain demand. They can fuel-switch. This is, in fact, a general feature of energy transitions. As a result, shifts in customer consumption patterns regarding one source of energy, whether as a result of social, economic, technical or policy developments, have repercussions for planning and balancing the energy supply and demand of other systems.

The Panel heard consistently that electrification and the energy transition will require greater technical co-ordination for the planning of Ontario’s electric and natural gas systems. Natural gas and electric systems are currently planned and regulated separately. Moving forward there is a need for coordination on an aligned vision, and for integrated planning and shared forecasting to understand the effects of fuel switching for infrastructure planning and development, and opportunities for system optimization across the electricity and natural gas delivery systems. Coordination will require sharing data and assumptions, aligning on demand forecasts, developing possible alternative scenarios, analyzing system capabilities to supply demand from fuel switching, integration of electric and natural gas efficiency and demand response programs, and coordination on the timing and location of new infrastructure development and asset refurbishment. Given the interests and tensions inherent in such a process – as well as the potential impacts on agency functions – the OEB and IESO will need to carefully support and maintain involvement.

Such a coordinated approach can not only enhance the efficiency of planning but also reduce the load on future adjudicative hearings. Electricity and natural gas planning coordination thus represents an innovation in anticipatory governance that has the potential to greatly enhance efficiency and expedite the process of energy planning and a cost-effective energy transition.

Policy-aligned regulatory mechanisms

With increased ability to fuel-switch comes the need to ensure there is a level playing field between gas and electric regulatory systems and that those funding mechanisms for cost-recovery and up-front capital requirements are aligned with the broader policy commitment for a clean energy economy.

The OEB’s Transmission System Code (TSC), which establishes rules for allocating the costs of electricity transmission upgrades, typically places the responsibility for covering the up-front costs of connection upgrades on customers. These costs can be significant and a major determinant in investment decisions that could bring regional economic and environmental benefits.

Proponents have raised concerns over the discrepancy in how up-front capital contributions are assessed and recovered between natural gas connections and electricity connections. In calculating the capital contributions associated with natural gas infrastructure, gas utilities can use an economic evaluation period (known as a revenue horizon) of up to 20 years for large industrial customers, while transmitters use 10-15 years, leaving a relatively higher capital contribution for electricity infrastructure as a proportion of its total costs. Furthermore, gas utilities can collect the capital contribution as a surcharge on gas rates, while transmitters are obligated by the TSC to collect capital contributions upfront. The short-term cost discrepancy of connecting customers and ratepayers could inhibit investments in electrification that have long-term sustainability and economic development benefits. For example, the up-front cost discrepancy might dissuade a residential developer from developing an ‘all electric’ or low carbon neighbourhood, and persuade them to instead build a traditional, natural gas-connected development to keep upfront costs manageable.

This example highlights the complexities of the natural gas governance framework, and how adjustments may be required to facilitate electrification and the energy transition. Levelling the playing field between electricity and natural gas might encourage developers and other customers to make choices that are more aligned with government’s clean energy economy commitment. Given the provincial government’s commitment to significantly expedite the construction of new housing and target 1.5 million new homes by 2030, regulatory action could be a significant support and ensure alignment with an overarching clean energy economy commitment.

Recommendation 15: To facilitate development of the clean energy economy, the OEB should conduct reviews of

1. Cost allocation and recovery policies for natural gas and electricity connections to eliminate discrepancies between how up-front capital contributions are assessed and how they can be collected between the two sources of energy. For example, the review should include, but not be limited to, examining the differences in the economic evaluation period (known as a revenue horizon) to determine capital contributions as well as the ability to collect the capital contribution as a surcharge on rates versus an upfront contribution
2. How natural gas utility infrastructure and Demand Side Management investments are evaluated to ensure new infrastructure is right sized for forecasted time horizons

Recommendation 16: The Ministry of Energy, working with the OEB, IESO, LDCs, municipalities and gas utilities, should develop a formal and transparent co-ordination framework that sets out the scope and objectives for enhanced planning co-ordination at the bulk, regional, and distribution levels in order to effectively pace and facilitate the fuel-switching, system optimization and enhanced levels of energy efficiency required by the clean energy economy.

The framework should ensure that each party’s technical expertise is respected and utilized appropriately to achieve the desired policy outcomes. This would include any required directives, regulatory changes, oversight mechanisms, and a clear and agreed upon understanding of specific roles and responsibilities for the entities involved. The framework should include the following:

1. Regulatory requirements via license amendments and codes (for the IESO) and Ministry undertakings or rule making authority under the OEB Act (for Enbridge) to require the IESO and Enbridge to coordinate bulk planning
2. Regulatory requirements via license amendments and codes (for the IESO and LDCs) and Ministry Undertakings or rule making authority under the OEB Act (for Enbridge) to require the IESO, Enbridge, and LDCs to coordinate regional planning
3. Development of standardized approaches to gas/electric coordination and demand forecasting at the distribution level, including coordination between Conservation and Demand Management (for electricity) and Demand Side Management (for natural gas) and with Comprehensive Local Energy Planning
4. OEB adjudicative regulatory processes (e.g. review of system plans, rate cases, and leave to constructs) should require the demonstration of gas/electric planning coordination outlined above via filing requirements on submitted plans and/or applications

Enabling the electricity distribution sector to achieve its full potential

Technology for the distributed generation and management of electricity is evolving quickly in maturity and cost-competitiveness, with the potential for disruptive change in the distribution sector in the near future. Distributed generation and storage, bi-directional flow, smart appliances, grid-interactive efficient buildings and electric vehicles, among other emerging technologies, present opportunities to improve the management of electricity resources, maximize value to customers, and minimize overall system costs. Where they are clean and reliable, DERs can also contribute to emissions reduction while supporting reliability at the local level. These innovations in scalable, often customer-owned energy solutions, have the potential to significantly alter the range and number of energy services delivered at the distribution level. In 2021, the IESO commissioned Ontario’s Distributed Energy Resources Potential Study, which showed that over a 10-year timeframe (2023–2032), it would be possible to cost-effectively meet all incremental system needs with DER capacity. When considering realistic levels of customer adoption and participation, not just economic potential, it said, “DERs are able to satisfy a material portion of the province’s energy needs – from 1.3 to 4.3 GW of peak summer demand by 2032.”

To maximize the cost-effective potential of DERs, the market models and regulatory frameworks by which the distribution sector is managed, and the ways in which the bulk electricity system is planned and managed, will need to evolve. The assessment of the achievable potential of DER technologies therefore must be complemented with rigorous analysis to understand how evolving (utility) business models and design of the wholesale market can enable DERs. New ways of organizing distribution system operation and participation, such as non-wire solutions, aggregators, virtual power plants, Distribution System Operators and other local energy markets, hold significant potential. The emerging consensus holds that DERs, while lacking some attributes of economies of scale compared to central grid infrastructure, offer opportunities to stack multiple value streams for the customer (including resilience) and the electricity system (from ancillary services to energy capacity).

The government, OEB and IESO should provide support and space for innovative models. They should work with utilities and DER proponents to enable these business models in a way that incentivizes DER participation to the benefit of the whole system. Some of this work is already underway. The Electricity Network of Ontario (formerly Smart Grid Forum) published several reports, including a concluding report in 2021 on Distribution System Structures For A High Distributed Energy Resource (DER) Future. IESO is subsequently developing its Enabling Resources Program to expand the electricity system services that these resources will be able to provide in the renewed IESO-administered wholesale market. The OEB has recently taken several steps to facilitate the prudent and effective integration of DERs, including a Distributed Energy Resources Connections Review (since 2019, with ongoing regulatory policy development) and the Framework for Energy Innovation process, which resulted in the 2023 report, Setting a Path Forward for DER Integration and additional guidance for electricity distributors. The OEB’s Innovation Sandbox acts as a testbed for system innovation in the electricity and natural gas sectors. An OEB-IESO Joint Study of Distributed Energy Resources Incentives is now underway, with results expected in Spring 2024.

Regulatory policy should provide support and space for innovative models of electricity resource management to evolve. This may extend to rethinking the traditional utility business model, that is, what constitutes distribution activity and how rate-regulated utilities earn a return from the services they provide. While re-thinking traditional business models, it will be important for regulatory policy to recognize that LDCs are diverse in their size, capabilities and need for capital investment. Where private sector participation lags and markets fail to adopt or proliferate valuable innovations, LDCs should be empowered to step into the breach, in the interest of enabling the energy transition and protecting customers. The adoption of innovative technologies and business models will vary. The guiding principles should be to ensure that any new and emerging models are supporting energy innovation, maximizing value for and protecting customers and leaving space for a diversity of solutions and market participants to compete.

In this context it is important to recognize that current planning and market rules, and the associated regulatory and business models were established before DERs and advanced distribution management systems were commercially viable options. As a result, it may be necessary to identify mechanisms to enable DERs and the local distribution system to achieve their full potential contribution to Ontario’s future energy system.

There is an urgent need to advance the regulatory environment to enable effective participation of DERs and eliminate barriers. A delay will mean that potentially cost-competitive solutions located at the distribution level cannot effectively compete during a time when Ontario will be investing in the expansion of the electricity grid to satisfy increased demand from electrification. This could lead to the entrenchment of traditional, bulk-level resource investment without effective competition from distribution-level resources and the erosion of the DER business case.

All innovation requires experimentation, which comes with certain commercial, rate, and reliability risks. There is rich opportunity for experimentation at the distribution system level, where technical innovation has been most active and system-level reliability and market competition concerns are significantly lower at current levels of DER penetration. Pilots and other forms of testing DER applications and business models have yielded important insights in Ontario and elsewhere. However, it is now time to move beyond pilots and develop a clear roadmap to full-scale implementation. Ontario must explore ways that implementation can proceed quickly while other regulatory and market reforms are underway.

It will be important to ensure that the IESO has the required level of visibility of DERs and their operations at the distribution level to maintain bulk system reliability – though careful analysis and discussion with stakeholders is needed to establish how much visibility and control are actually required. The value of visibility goes both ways: hosting capacity and load maps can enable proponents to understand much more quickly where DERs can be connected and what value they may provide. California is requiring utilities to make these available, and in Alberta, distribution utilities ATCO, ENMAX and FortisAlberta have all published hosting capacity maps, in addition to the Alberta Electricity System Operator, for the transmission system.

Recommendation 17: The OEB and IESO must continue to find ways within their existing mandates and in anticipation of the clean energy economy policy statement to provide proactive and transparent thought leadership on regulatory policy. Energy agencies should work to examine where existing rules and practices disadvantage the cost-effective participation of clean energy solutions, and especially in how distribution resources can participate across the value chain of the entire energy system.

The goal should be to develop an open investment environment that creates a level playing field in which DERs can provide their full value to customers by effectively competing with one another and with bulk-system resources.

1. To enable distribution-sector innovation, build capacity and encourage reasonable risk-taking to maximize customer and community value, the government, IESO and OEB should work with utilities to develop a vision and clear pathway for system-wide application to realize the maximum capability of the distribution system and DERs.
2. The OEB should support LDC applications in grid modernization, establishing a process and technical threshold to determine which LDCs will be enabled to locally procure and dispatch DERs.
3. LDCs should be required to enhance their capabilities to procure and actively manage DERs as Non-Wires Alternatives to meet distribution level needs.
4. The OEB should continue and enhance the requirement for LDCs to file electrification readiness plans (ERPs). ERPs should demonstrate consideration of Comprehensive Local Energy Plans and processes.
5. The OEB should have a clear and consistent approvals framework for distribution level approaches that can help maximize the value of the distribution sector and reduce barriers to adoption. This should include grid modernization upgrades that enable efficient energy management, such as two-way telemetry, tools for enhanced conservation and demand management (CDM), and non-wires alternatives to traditional distribution infrastructure enhancements. As needed, the OEB should review policies, such as the Affiliates Relationship Code, to enable greater flexibility for LDCs without compromising private sector participation.
6. The IESO should critically assess and report back on the extent to which its systems, including market rules, dual participation model, and interoperability requirements, can be improved to remove barriers to the effective participation of DERs and innovation in business models.
7. Accountability frameworks should be codeveloped by IESO, OEB and LDCs to ensure good coordination and to manage any conflicts, real or perceived. To promote interoperability and increase the value of distributed solutions, all work should be undertaken with a view to developing a common platform, or limited number of platforms, on which LDCs can converge. The IESO can play a key role in facilitating this process.