Happy New Year. Before the year kicks into high gear, we thought it would be useful to share with you some of the most important themes and regulatory developments in the Ontario energy sector in 2023, with our annual Year in Review edition of the Shepherd Rubenstein Energy Regulatory Update. Stick around at the end for some thoughts for 2024 from our editor. We will have out detailed Q4, 2023
2023 saw the Ontario Government release its Powering Ontario’s Growth: Ontario’s Plan for a Clean Energy Future, which outlines the actions the province is taking and plans to take to meet the increasing electricity demand over the two decades. It builds on recommendations included as part of the IESO’s Pathways to Decarbonization Report and subsequent public consultation.
Just as we pointed out in last year, the energy transition was present in almost every regulatory discussion and decision over this past year. We all await the report of the Electrification and Energy Transition Panel (EETP), who undertook consultations this year, it is expected to be released in early 2024.
1. Electricity Procurement
The biggest development of 2023 was significant resource procurement activity.
Currently underway is the Long-Term 1 RFP (LT1 RFP) process, which is expected to procure 2,500 MW of dispatchable new build resources. The submission deadline was in mid-December, and contracts are expected to be offered to successful proponents in Q1/Q2 2024.
Earlier, in the year, as a result of its Expedited Long-Term LT1 (E-LT1) RFP, the IESO awarded contracts for 882 MW of non-emitting capacity from 15 storage facilities and 295 MW of natural gas capacity from on-site expansion of two existing facilities (about half the target capacity). An additional 286 MW of natural gas capacity was contracted as part of the Same Technology Upgrade process. The annual Capacity Auction procured a record 1,867MW of capacity for summer 2024 and 1,310 MW for winter 2024/2025.
The IESO also finalized a 20-year agreement with Oneida Energy Storage LP 250 MW storage facility, and a contract to extend Brighton Beach Generation Station to 2034 (with incremental capacity), and entered into a Memorandum of Understanding with Hydro-Québec to negotiate a new capacity sharing agreement that would swap a minimum of 600 MW of capacity per season.
At the direction of the Minister of Energy, the IESO developed the Small Hydro Program, to provide new contracts for existing hydroelectric facilities with installed capacities of 10MW and below. Minister of Energy also asked the IESO to assess two proposed pump storage projects to determine if they would provide positive value to the electricity system. The Minister proposed that, if they are implemented, they would be OEB rate regulated.
In December, in response to a request from the Minister of Energy, the IESO issued a Resource Adequacy Update, focused on Ontario’s system needs beginning in 2029. Resource Adequacy Update includes a 5000 MW procurement target for energy needs to be met through 3 bi-annual long-term RFPs. The first of these, LT2 RFP is expected to take place in 2025. The IESO has begun engagement for it, and is anticipated to target 2,000 MW of new energy producing capacity.
To help offset the cost of procurement of these resources (and other programs and infrastructure costs), the Minister of Energy asked the IESO to report back on options for a Future Clean Electricity Fund, funded from proceeds from the sale of Clean Energy Credits held by the IESO and OPG.
2. The Future of Natural Gas
Over the past year there has been a heated discussion regarding the future of natural gas and natural gas generation.
As discussed earlier, the IESO awarded contracts for 581 MW of natural gas generation as part of the E-LT1 RFP and Same Technology Upgrade process. Additional natural gas generation is expected to be procured as part of the on-going LT1 RFP.
As part of that LT1 RFP procurement, project proponents must get consent from the host municipal council. This created a lively debate between project proponents and opponents (primarily environmental groups). Recognizing the issue, the Minister asked the IESO to ensure it made itself available to municipal councils to answer questions on Ontario’s electricity system needs. Municipal councils in Napanee, and Windsor have provided their consent to potential projects. Those in Thorold, Halton Hills and Kingston have refused to provide that necessary consent, effectively killing some proposed projects that were expected to have made a bid in the LT1 RFP.
The future of natural gas as a fuel and heating source was debated through most of the year as part of Phase 1 of Enbridge Gas’ 2024-2028 rates application. Just before the December holidays, the OEB issued its Phase 1 decision, finding that the energy transition poses a risk that assets used to serve Enbridge’s customers will become stranded, and the company has not provided an adequate assessment of that risk to demonstrate its plan is prudent. One consequence of that finding was an OEB decision (with one commissioner dissenting) that to reduce stranded asset risk, beginning in 2025 all new small volume connecting customers will bear their connection costs upfront (as opposed to spread over 40 years as now). The next day, the Minister of Energy expressed his “extreme disappointment” in that part of the OEB decision, as it could result in added costs of building new homes. He announced that the Government would use its authorities to pause it, and introduce legislation, to reverse it.
Earlier in the fall, the OEB also held an oral hearing on Enbridge’s application to construct the Panhandle Regional Expansion Project, a major transmission pipeline expansion needed for growing greenhouse and natural gas generator demand in Southwest Ontario. A significant part of the debate before the OEB is who should be required to pay for the project, the customers driving the project need, or all customers.
There was also activity regarding natural gas expansion.
The Ministry of Energy launched a consultation on the future of the Natural Gas Expansion Program.
The OEB approved a number of Enbridge’s applications for leave to construct natural gas expansion projects that had received funding through the Natural Gas Expansion Program. Those projects have seen opposition at the OEB by environmental intervenors, and construction was temporarily halted as a result of a motion to review, which was ultimately denied.
3. Nuclear Renaissance
The Government of Ontario has clearly signaled that nuclear power will remain a significant component of the energy mix well into the future.
The Minister of Energy made two major announcements regarding new nuclear development.
First, he announced the beginning of pre-development work to construct new large scale nuclear generation on the Bruce Power site. Bruce Power will start necessary consultations and undertake a federal environmental assessment to determine the feasibility of siting up to 4,800 MW of new nuclear generation on the existing site. The Minister has asked the IESO to develop a cost sharing and recovery framework with Bruce Power for the Impact Assessment process.
Second, the Minister announced that the Government is working with Ontario Power Generation to commence planning and licenses for three additional small modular reactors (SMRs) at the Darlington Nuclear site.
The Minister of Energy also asked the IESO to work with OPG and Bruce Power to develop a feasibility study and business for future nuclear generation facilities. In addition, OPG was to send the Ministry of Energy its feasibility assessment for refurbishing Pickering B units by the end of 2023.
4. Transmission Expansion
Increased electricity demand will require significant transmission system expansion.
The Government of Ontario issued an Order-in-Council declaring three new transmission projects (a new 230 kV transmission line from the Mississagi TS to the Third Line TS, a new 500 kV transmission line from the Mississagi TS to Hanmer TS, and a new 230 kV transmission line from the Dobbin TS to either the Cherrywood Ts or Clarington TS) as priority projects under section 96.1 of the Ontario Energy Board Act. The Minister of Energy issued a directive to the OEB requiring it to amend Hydro One’s transmission license to require the company to develop and seek all necessary approvals for the three projects.
The IESO recommended that the Hydro One construct phase 2 of the Waasigan Transmission Line between Atikokan and Dryden.
There has also been movement on a more competitive process for the development of transmission projects. As requested by the Minister of Energy in implementation of Powering Ontario’s Growth, the IESO initiated an engagement to develop a Transmission Selection Framework. In the summer, the Ministry of Energy said that it would engage with indigenous communities and interested transmitters who have expressed an interested in constructing a new 230 kv line between the Wawa TS and Porcupine TS. There are at least two groups (Transmission Infrastructure Partnerships 9, and Wabun Tribunal Council/Hydro One) seeking to construct and own the line.
The OEB revised the filing requirements for electricity transmission leave to construct applications.
5. Electric Vehicles
There was a focus at the OEB on facilitating the adoption of electric vehicles (EVs).
As part of its Electric Vehicle Integration initiative, the OEB released the results of the survey of electricity distributors and EV charging service providers, and a consultant’s report on Electricity Delivery Rates for EV Charging.
The OEB also expanded the scope of its DER Connection Review to include system readiness for EV charger connections. That work resulted in the OEB issuing a Notice of Proposal to Amend the Distribution System Code (DSC) to facilitate connection of EV charging infrastructure. The Notice creates Electric Vehicle Charging Connection Procedures which standardize many elements of the connection requirements and process.
In late December, the Federal Government finalized its new Electric Vehicle Availability Standard, which would set annual sales targets of zero-emission light duty vehicles annually, leading to a requirement of 100% by 2035.
6. Distributed Energy Resources, and Non-Wires and Non-Pipe Alternatives
A number of big steps were taken to require consideration of non-wires and non-pipes alternatives to meet system needs, and to promote the use of Distributed Energy Resources (DERs).
In January, the OEB released its long-awaited report arising from its Framework for Energy Innovation (FEI) consultation on integrating DERs into the distribution planning and operations, as well as the use of third-party owned DERs as non-wire alternatives. The FEI: Setting a Path Forward for DER Integration Report set out some initial OEB guidance and laid out a multi-year implementation plan.
The first part of the implementation plan included the issuance of filing guidelines for incentive by electricity distributors to use third-party DERs, as well launching a consultation to develop a Benefit-Cost Analysis (BCA) Framework for addressing electricity system needs. By the end of the year, the OEB had released a draft BCA Framework Handbook for comment.
The IESO released a Guide to Assessing Non-Wires Alternatives as part of the Integrated Regional Resource Plan process. Together with the OEB, the IESO has commissioned a Joint Study of DER Incentives.
In preparation for the next CDM framework, the Ministry of Energy sought input on the future of electricity conservation programs. The IESO launched a new stakeholder engagement initiative that explores enhancements to demand-side resource participation in the IESO administered markets and programs.
To better understand DER adoption, the OEB now requires distributors to report on non-net metered embedded generation and storage devices connected to its system. The OEB also amended the Distribution System Code (DSC) to facilitate DERs through the elimination of certain capital allocation exemptions, capacity allocation deposits, and revised connection cost deposit refund processes and timelines.
At the end of the year, the OEB launched a consultation to develop a policy on standby rates.
7. Federal Investment and Regulation
The Federal Government’s has significantly increased its investment and regulation to promote clean energy.
In August, the Federal Government issued Powering Canada Forward: Building a Clean, Affordable, and Reliable Electricity System for Every Region of Canada, which outlines its vision for the electricity sector.
Soon after, the Federal Government published for comment a draft of its Clean Electricity Regulations (CER) , aimed at achieving a net-zero electricity grid by 2035. The CER would effectively prohibit grid-scale natural gas electricity generation, except for a total of 450 hours a year, by 2035 for all new facilities commissioned after 2025, or the later of 2035 or 20 years after they were commissioned if it was before 2035.
The IESO provided feedback that in its view the CER as drafted are unachievable in Ontario by 2035 without risking the reliability of the electricity system, electrification of the broader economy and economic growth. The Minister of Energy has asked the IESO to provide a detailed assessment on the CER’s impacts in Ontario.
Earlier in the year, the Federal Minister of Energy and Natural Resources announced the creation of the Canada Electricity Advisory Council to provide him with expert advice. In December, it issued an Interim Report, and launched a consultation. Natural Resource Canada also conducted a Request for Information seeking input regarding regulatory, policy and market barriers and opportunities for accelerating the pace of electrification and electricity grid modernization.
At its centerpiece, it included the Clean Electricity Investment Tax Credit, a 15% refundable tax credit available for eligible investments, including non-emitting electricity generation systems, electricity storage systems, and equipment for electricity transmission between provinces/territories. This is available to both taxable and non-taxable entities (i.e. indigenous communities, crown corporations, publicly owned utilities, and pension funds). In order to access the tax credit in each province/territory, there will be a requirement for a commitment by a competent authority that the federal funding will be used to lower electricity bills, and a commitment to achieve a net-zero electricity sector by 2035.
The Budget also included a new Investment Tax Credit for Clean Hydrogen, expanded eligibility of the Clean Technology Investment Tax Credit to include geothermal energy systems, enhancements to the Carbon Capture, Utilization, and Storage (CCUS) Investment Tax Credit, funding to recapitalize the Smart Renewables and Electrification Pathways Program, and renewal of the Smart Grid Program. It also announced a Canadian Infrastructure Bank investment of $20Bn in clean power and infrastructure priority areas, and that the Canada Growth Fund will design a Contract for Differences mechanism to backstop figure prices of carbon and hydrogen.
The Fall Economic Statement, announced that the Canada Growth Fund will be allocated $7Bn, on a priority basis, for carbon Contract for Differences and offtake agreements. It also provided further information on delivery timeline for the various investment tax credits. Accompanying legislation was introduced implementing the CCUS and Clean Technology Investment Tax Credits.
There are debates about the limits to the Federal government authority, and several legal battles are coming next year. In the fall, the Supreme Court of Canada released its decision in the reference on the Impact Assessment Act, deciding that the “designated project” portion of the legislation was outside of the Federal jurisdiction. Alberta has signaled it will challenge the constitutionality of the CER if implemented. As a result of perceived unfairness in the Federal Government’s heating oil exemption from the federal carbon charge, Saskatchewan passed legislation to enable it to require SaskEnergy to stop collecting and remitting the carbon charge on natural gas as of January 1, 2024.
There was a lot of activity on the innovation front.
The OEB issued its Innovation Handbook, a compendium of existing OEB policies and materials related to innovative projects and proposals.
As part of its Innovation Sandbox, the OEB launched the Innovation Sandbox Challenge, and ultimately provided one-time funding to six projects. In April, the OEB released its Innovation Sandbox 2.0 Report covering activities through the end of 2022. The OEB and the IESO also issued their Innovation Sandbox/Grid Innovation Fund Joint Target Call Interim Report
In addition to the launch of the Ultra-Low Overnight Time of Use Pricing Plan, there were other initiatives aiming to innovate electricity pricing. The OEB provided an update regarding its Non-RPP Class B pricing pilot program. As no draft or final applications were received, the OEB is developing new options to assess alternatives to the commodity pricing structure. At the direction of the Minister of Energy, the IESO developed and launched the Interruptible Rate Pilot.
As part of implementation of its Low-Carbon Hydrogen Strategy, the Government of Ontario announced the creation of the Hydrogen Innovation Fund (HIF). The IESO was directed to administer the HIF, and by year end 10 projects had been awarded HIF funding.
To support the OEB’s objective to facilitate innovation in the electricity sector, the Government of Ontario passed legislation amending the Ontario Energy Board Act, to permit the OEB to exempt certain licensing requirements with respect to specified activities for the purposes of participating in a pilot or demonstration project.
There were two noteworthy OEB decisions related to innovative projects. The OEB approved a Settlement Proposal in PUC Distribution’s 2023 distribution rates application, which included a unique cost recovery and performance incentive mechanism related to its previously approved Sault Smart Grid project. As part of Elexicon Energy’s Incremental Capital Module (ICM) funding application, the OEB approved substantially reduced funding for its proposed community-wide smart grid project.
As of the end of the year, all but 5 electricity and natural gas distributors had fully-implemented Green Button.
The Ontario government announced a proposal to allow Class A customers under the Industrial Conservation Initiative (ICI) to enter into power purchase agreements (PPAs) with renewable generation facilities to allow them to offset their peak demand.
With climate change expected to increase the need for resiliency of the electricity system, in response to the Minister of Energy’s direction the OEB undertook a consultation on distributor resilience, responsiveness, and cost efficiency. The OEB sent a Report to the Minister of Energy, who has endorsed a number of the recommendations, and asked that the OEB begin to develop policies and implement them.
Thoughts For 2024
Last spring, I had the opportunity to speak on a panel discussing the topic of affordability in the context of how the energy sector will contribute to meeting our net-zero commitments. My message to the audience that day, which I have often repeated, is that the number one threat to meeting those decarbonization goals is cost.
The path to meet our net-zero commitments is much like driving up a steep mountain. You need constant forward momentum for the climb, or you will just start going backward. If anything, you need to keep pressing the accelerator. Nobody doubts that the level of investment needed will be significant. At the same time, customers’ willingness and ability to pay to transform our energy system has real limitations.
Without a focus on customer affordability and least-cost planning and execution, in all aspects of the energy transition, there will be inevitable backlash. The risk is that it will not just halt any momentum that has been achieved, but will set us backward. The history of the energy sector, in Ontario and across the country, is full of examples of government intervention when rates exceed what they believe customers are willing to pay.
Powering Ontario Growth mentions affordability, but there has not been much discussion of what that specifically means and how to achieve it. In Ontario, taxpayer-funded rebate and subsidy programs have an important role, but at a cost of approximately $6 billion this year alone, it is not a sustainable solution to what is a an extremely difficult problem with no easy solutions.
Whether it’s 2030, 2035, or 2050, the clock is ticking. We must accelerate the pace of change, but with a relentless focus on minimizing costs.
Let’s hope the Electrification and Energy Transition Panel, along with any subsequent changes that the government may make, creates a durable long-term approach that focuses on costs and affordability. The sheer magnitude and scale of the investments and changes needed in the energy system call for more, not less, oversight and scrutiny. The voices of those who pay all the costs of the energy system—customers, who themselves increasingly have diverse views—need to be at the core of those energy decision-making processes. Limiting those voices, as some continue to try, is counterproductive.
Regardless of where you sit around the table—whether as a policymaker, regulator, utility, customer representative, project developer, energy service provider, or simply an interested observer—it is in all our collective interests to keep customer impacts at the forefront of the energy transition. Failure to do so jeopardizes our ability to fulfill our net-zero commitments, as we start sliding backwards down the mountain. –MR
As always, if you have any questions, or think we can be of assistance to you or your organization, please do not hesitate to reach out to Mark Rubenstein at email@example.com.
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