VALLEY FORGE, Pa. — Looking ahead to the possibility of future emergency orders from the U.S. Department of Energy, stakeholders endorsed a PJMissue charge to establish a more permanent set of rules for how to allocate the cost of keeping generation online beyond its desired deactivation date when ordered by the federal government.
PJM Executive Director of Member Services Jennifer Tribulski told the Markets and Reliability Committee on June 18 that the RTO envisions a new senior task force meeting two to three times a month, with a goal of submitting a filing to FERC in October.
The issue charge designates the content of future DOE orders and the “operating protocols and parameters agreed to by the resource owner” as out of scope.
The Members Committee voted to support a proposal to assign all PJM consumers a share of the cost of continuing to operate Constellation Energy’s Eddystone Generating Station. The company was ordered by DOE to keep Eddystone online past its May 31 deactivation date to ensure resource adequacy, but the order did not specify how Constellation should be compensated. (See PJM Stakeholders Propose Cost Allocation Models for DOE Emergency Orders.)
The package from Gabel Associates received 86% sector-weighted approval in the June 18 vote, making it the only proposal to receive the committee’s support over two proposals from PJM and three from the East Kentucky Power Cooperative (EKPC). The vote results are advisory to inform the PJM Board of Managers’ determination on how to proceed.
Stakeholders commented on the proposals to the board in a Critical Issue Fast Path (CIFP) meeting, which was closed to media and held after the MRC meeting but just before the MC vote. The CIFP process was conducted on a tight five-day timeline to avoid a gap in billing.
All of the proposals include the same June 1 implementation date, transparency provisions, billing frequency and cost allocation calculation formula. Where they differ is how to determine which consumers should be allocated a share of the costs and whether the governing document revisions should address possible future DOE emergency orders.
Gabel’s proposal, PJM Package C and EKPC Package E would allocate the costs to all PJM consumers, while PJM’s Package A would narrow the allocation to specific locational deliverability areas (LDAs) or zones if future emergency orders specified that a resource adequacy issue was geographically isolated. EKPC Packages D and F would allocate the costs to specific LDAs if they clear short of their reliability requirement; otherwise, they would use an RTO-wide allocation.
Gabel and EKPC Package E both would apply only to the Eddystone order expiring in August, with the other five including differing ways of addressing any future emergency orders to keep generation online.
Constellation Vice President of Wholesale Market Development Adrien Ford said the company could not support Gabel’s proposal without modifications to allow it to continue to provide cost allocation beyond the Aug. 28 expiration of the DOE order in the event the department requires Eddystone to remain online longer.
Exelon Director of RTO Relations and Strategy Alex Stern said he supports the Gabel proposal and trusts the board to make any necessary adjustments, such as the applicability to future orders.
Carl Johnson, representing the PJM Public Power Coalition, said some members supported the Gabel proposal because it would limit the changes to the current Eddystone order, with the belief that there will be more emergency orders issued in the next few weeks and those should be addressed as they come up.
Dominion Presents Proposal to Change Dual-fuel Definition
VALLEY FORGE, Pa. — Dominion Energy presented the Markets and Reliability Committee with a quick-fix package to expand the definition of dual-fuel generation in the Reliability Assurance Agreement (RAA) to include generation capable of running on a backup fuel type with off-site storage and dedicated delivery.
The current language restricts the dual-fuel classification to gas combustion turbines or combined cycles capable of starting and operating on an alternative fuel with on-site storage. Dominion’s James Davis said that would exclude an LNG storage facility the company is building in Virginia. Dedicated pipelines would run from storage to two CC generators, a configuration not recognized as dual-fuel under the existing rules, but which Davis said provides a comparable degree of reliability.
The quick-fix process allows a problem statement, issue charge and proposal to be brought concurrently. The proposal would be effective for the 2028/29 Base Residual Auction (BRA), the schedule of which has fuel-type attestations due in November.
Calpine’s David “Scarp” Scarpignato said the proposed language could loosen the definition of fuel source to allow configurations that would not deliver the reliability expected from dual-fuel units. When Calpine proposed changes to the dual-fuel definition in 2024, the Independent Market Monitor recommended changes to the proposed language to ensure the backup fuel actually could be used. Scarp gave the example of a generation owner seeking dual-fuel status for a resource with a small on-site storage tank intended to be resupplied by truck as needed. (See “Quick Fix for Dual-fuel Classification Endorsed,” PJM MRC Briefs: April 25, 2024.)
Stakeholders Bring Alternative SATA Issue Charges, Endorsement Delayed
The committee deferred voting on an issue charge seeking to establish a ruleset for battery storage to be installed and operated as a transmission asset (SATA) to allow more time to consider two alternatives brought by Constellation and Exelon.
The PJM issue charge has been discussed at several meetings in recent months, with voting delayed to hold education on how SATA would operate and its implementation in other RTOs.
Building off PJM’s issue charge, Constellation added several key work activities (KWAs) to identify the use case for SATA, when the batteries would run and more thoroughly consider the market effects storage might have. Stakeholders seeking more consideration of the topic before voting on an issue charge have argued inadequate rules could allow batteries on a regulated rate to displace market-based resources.
Independent Market Monitor Joe Bowring has said in past meetings there is not a way to meaningfully distinguish between a resource injecting energy for transmission support or market participation.
Exelon proposed edits to the Constellation language focused on ensuring SATA would be treated and used the same as other transmission solutions. It replaced a Constellation KWA to “identify what the market impacts could be and a commitment to address them” with “ensure a storage device identified as transmission only and not a market resource is treated no differently than any other transmission asset, including with respect to market impacts.”
1st Read on 3rd Phase of Hybrid Resource Rules
PJM presented revisions to several manuals to conform with FERC’s approval of the third phase of PJM’s hybrid resource rules (ER25-1095). Elements of the manual changes were endorsed by the Planning, Operating and Market Implementation Committees earlier in June. (See “3rd Phase of Hybrid Resource Rules Endorsed,” PJM MIC Briefs: June 2, 2025.)
Phase 3 expands the hybrid model to include pairings of co-located non-inverter-based generation and battery storage as one market unit. Hybrids with a capacity commitment would fulfill their obligation to offer into the energy market by submitting their forecast output, capped at the inverter capability, while a hybrid with a storage component should offer the “anticipated intermittent and battery output.”
Revisions to the formula for lost opportunity cost (LOC) credits would make eligible storage and hybrid resources instructed to increase charging to mitigate transmission constraints or reliability issues. Resources instructed to reduce charging would not be eligible.
The definition of closed- and open-loop batteries also would be revised to allow resource owners to determine how a storage unit should be classified. For instances where storage is capable of charging from the grid, the resource owner would be permitted to choose whether to offer it as open- or closed-loop, allowing for situations where a battery is physically capable of charging but the owner has determined not to operate it in that fashion.
PJM Presents Capacity Market Manual Revisions
PJM presented a first read on proposed revisions to Manual 18: PJM Capacity Market to conform with several filings the RTO has made in recent months reworking elements of the market (ER25-682, ER25-785, ER24-2995 and ER25-1357).
The changes include modeling the expected output of some resources operating on reliability-must-run agreements as capacity; implementing a minimum capacity market clearing price and lowering the price maximum; removing the addback for energy efficiency resources; codifying the BRA schedule; maintaining a CT as the reference resource; and setting an RTO-wide capacity performance penalty rate. The revisions also would remove an exemption from the requirement that resources offer into the capacity market for intermittent, storage and hybrid resources. (See FERC OKs Changes to PJM Capacity Market to Cushion Consumer Impacts.)
Members Committee
Board to Hold Dialogue with Stakeholders at MC Meetings
PJM Board of Managers Chair David Mills told the Members Committee that attending board members will remain at the Conference and Training Center (CTC) for the full meeting to facilitate a dialogue with stakeholders. That includes a commitment to remain in the region overnight to allow discussions to continue after the MC concludes. Mills was joined by board members Paula Conboy and Vickie VanZandt at the CTC, with other members attending virtually.
“This is an opportunity for us to hear out one another. And all this is against the backdrop of our responsibility as board members …. to hear what you have to say,” Mills said, adding that listening to stakeholders does not mean the board will take sides on issues or compromise its independence.
At the Annual Meeting on May 12, Mills broached the idea of adding a standing MC agenda item for the board and stakeholders to bring issues they wish to discuss. Several stakeholders cited lacking transparency and access to the board as their reason for voting against re-electing two board members during the meeting. (See PJM Stakeholders Vote Out 2 Board Members.)
Much of the discussion during the June 18 meeting centered on the format future discussions should take, with the aim to have them begin in earnest at the July 23 MC meeting. Mills said his vision is for the format to be more informal than that of the Liaison Committee (LC), with conversations rather than prepared speeches. That could take the form of moving to group conversations in the lobby or remaining in the conference room.
PJM Proposes Revisions to Antitrust Language
PJM Assistant General Counsel Eric Scherling presented updated antitrust guidance for stakeholder meetings intended to bolster the RTO’s recommendations for avoiding conduct that could run afoul of antitrust law. He characterized the guidance as a clarification, rather than a change, in the language.
The changes affect the antitrust language included in meeting agendas, which are referenced by committee and stakeholder group chairs before meetings begin, as well as guidance on the PJM website. Scherling said the change in guidance is not in response to any particular stakeholder behavior, but rather making improvements that PJM has identified.
While stakeholders can discuss how trends and forecasts may affect market pricing or costs, disclosure of non-public information, such as bidding practices, could violate federal antitrust statutes. The guidance states that “informal, hypothetical or joking references to these topics should be avoided.”
Scherling said there are a pair of protected areas where market practices or non-public information could be discussed without violating federal law. The Noerr-Pennington doctrine allows for good-faith advocacy for federal agencies to adopt proposals that may reduce the competitiveness, while Parker immunity allows uncompetitive activity so long as it is authorized by state policy.
Changes to Liaison Committee Registration Discussed
PJM plans to close registration for future LC meetings a few days in advance to ensure staff have time to validate the credentials of attendees ahead of time, Manager of Stakeholder Process and Engagement Michele Greening said.
For the July 28 meeting, that means registration will close at 5 p.m. July 24, with no late registrations accepted.
Constellation Vice President of Wholesale Market Development Adrien Ford said prior to the COVID-19 pandemic, the LC meeting was a great opportunity for members to speak with the PJM Board of Managers about pressing matters and network with other attendees afterward. In-person attendance has not returned to pre-pandemic levels, however, and there have been fewer meetings recently, making the committee a less rich experience.
PJM CEO Manu Asthana said part of why there have been fewer LC meetings is the board has been meeting more regularly to address pressing issues as they arise.
MISO Midwest entered emergency status June 23 during the RTO’s first serious heat wave of the summer.
MISO declared a maximum generation event for 4-10 p.m. ET, when it estimated that all available resources would be in use. The Step 1 declaration allows the RTO to commit emergency resources and curtail export schedules.
The grid operator said a combination of wide-ranging heat, higher-than-forecasted load, forced outages and restricted transfer capabilities necessitated escalating its earlier emergency warning to an emergency event.
Based on forecasts made in the morning, MISO foresaw the most pressing problem occurring about 7 p.m. ET, when its approximately 121 GW of available capacity would come a few megawatts shy of its load forecast. By afternoon, however, it no longer predicted a deficit.
MISO also issued a maximum generation warning for June 24.
The RTO originally forecast 122.8 GW of demand for June 23. At 1 p.m. ET, its members were serving almost 114 GW of load at a marginal cost of $324.77/MWh. Indianapolis, Detroit and St. Louis were forecasted to hit 95 degrees Fahrenheit or higher June 23. At midday, solar generation was contributing about 12.5 GW and wind 13 GW.
By 6 p.m., MISO was meeting about 119 GW of demand with the help of 5.2 GW of imports priced at about $139/MWh. By then, it had recalibrated its peak demand forecast down to about 120.7 GW.
MISO has been preparing for a sweltering summer. In an outlook issued in May, it estimated it could see a June peak load of nearly 122 GW in a high-demand scenario but expected the peak more likely would top out at 115 GW. The RTO’s July forecast called for a 122.6 GW peak under normal conditions and a high-demand scenario of 129.3 GW. (See MISO Braces for Hot Summer, Potential 130-GW Peak.)
MISO also initiated a capacity advisory for the South region June 21 due to forced generation outages.
Ontario is putting its chips on nuclear power and natural gas to meet its growing energy demand while directing IESO to incorporate gas distributors and the province’s economic development goals in its system planning.
The province’s first-ever integrated energy plan, Energy for Generations, released June 12, seeks to ensure sufficient capacity for a forecast 75% increase in electric demand over the next 25 years.
Authorized by the 2024 Affordable Energy Act, the plan seeks to integrate planning for electricity, natural gas, hydrogen and emerging fuels along with energy efficiency, demand-side management and distributed energy resources. The five-year planning cycle will provide the “long-term certainty [needed] to make smart investment decisions,” according to the plan, which was authored by the province’s Ministry of Energy and Mines.
“As the world searches for affordable, secure, reliable and clean energy, Ontario is doing big things,” Minister Stephen Lecce wrote in the foreword to the plan. “We are leading the largest expansion of nuclear energy on the continent, building the largest battery storage fleet in the country, adding thousands of kilometers of new electricity transmission and modernizing our grid to meet the needs of tomorrow.”
Changing Planning
The ministry declared an end to the “siloed approach” to planning, saying, “For too long, decisions about electricity, natural gas and other fuels have been made separately, without a unified view of how they work together to power the province’s economy and communities.”
Such coordination will avoid situations where non-pipe alternatives such as electric heat pumps “are advanced without accounting for their impact on local electricity demand and grid capacity,” the plan says. (See related story, Ontario Energy Plan Gives IESO Long ‘To Do’ List.)
IESO will be required to identify transmission projects that would be needed under high-growth forecasts to conduct at least annual meetings of Technical Working Groups in each planning region, “in consultation with [local distribution companies], [transmission companies], municipalities and major customers, to ensure more frequent sharing of demand forecasts, system needs and planned infrastructure investments.”
Long Bridge for Natural Gas
While the plan endorses an “all of the above” approach to fuel diversity, it places a heavy emphasis on retaining and expanding nuclear power and natural gas.
Natural gas makes up 36% of Ontario’s end-use energy consumption and is the home heating fuel for about 75% of residential customers. While climate activists are calling for replacing gas with renewable generation and home electrification, the Ontario government said it supports “the rational expansion of the natural gas network” to serve homeowners in rural and northern areas who do not have access.
Ontario sees natural gas’s role in electric generation shrinking to almost zero by 2050. | Ontario Ministry of Energy & Mines
Chapter 5 of the plan is the ministry’s Natural Gas Policy Statement, which concludes there are few alternatives to gas for Ontario’s industrial and agricultural sectors and warns “a premature phaseout of natural gas-fired electricity generation is not feasible and would hurt electricity consumers and the economy.”
Although it provides only about 16% of the province’s power, natural gas represents 28% of its generation capacity, giving it a critical role in meeting system peaks.
The ministry says gas-fired generation will increase through the 2020s and 2030s because of rising demand and planned nuclear refurbishments. “This will result in a short-term increase in electricity system emissions. However, as new non-emitting supply, particularly new and refurbished nuclear generation comes online, emissions from electricity generation are expected to decline significantly,” the plan says.
The province directed the Ontario Energy Board (OEB) to provide a report on expanding its mandate over natural gas and electricity to include alternate energy sources, hydrogen pipelines, carbon dioxide pipelines and district energy systems.
It directed OEB to improve the alignment between gas and electricity policies, citing limits on the grid’s ability to serve customers switching from gas to electric heat. It also ordered OEB to develop a new gas connection policy to support faster home building. “OEB will take steps to encourage — and, where appropriate, require — regulated natural gas distributors and LDCs to participate in regional and bulk electricity planning processes,” it says.
The province said it supports a new east-west energy corridor to expand access to Western Canadian natural gas and crude oil and reduce reliance on U.S. imports, which account for two-thirds of Ontario’s gas consumption.
Big Bets on New Nukes
Ontario also is making big bets on nuclear power, which generates more than half of the province’s electricity. In a high electrification scenario, IESO says, the province could need up to 17,800 MW of new nuclear generation in addition to its current 12,000 MW.
On May 8, Ontario authorized Ontario Power Generation (OPG) to begin construction on the first of four small modular reactors at the Darlington nuclear site. The initial unit, targeted for commercial operation in 2030, would be the first grid-scale SMR in the Group of Seven countries, of which Canada is a member. OPG says building all four SMRs, a total of 1,200 MW, will cost $20.9 billion. The additional SMRs could come online between 2033 and 2035. (See Ontario Greenlights OPG to Build Small Modular Reactor.)
Site preparation work is complete for the first of four small modular reactors at Ontario Power Generation’s Darlington site. | Ontario Power Generation
The government also is supporting the expansion of the Bruce Nuclear Generating Station, referred to as Bruce C, which could add up to 4,800 MW.
The plan enrolls IESO in a New Nuclear Technology Panel with OPG and Bruce Power “to ensure prospective sites for new nuclear generation are considered in electricity system and transmission planning studies.”
Hydropower
The plan calls for expanding and refurbishing the province’s hydropower resources, which provide about 24% of Ontario’s electricity, behind only nuclear.
OPG, which is investing $4.7 billion to refurbish and expand its 66 hydroelectric generating stations, has identified up to 4,000 MW of potential new hydropower in northern Ontario. The government is supporting early-stage development for two new sites in the Moose River Basin: Nine Mile Rapids and Grand Rapids.
The plan orders IESO to launch a program to re-contract 26 hydroelectric facilities larger than 10 MW, a total of more than 1,000 MW. The ISO already is working to recontract about 80 small hydroelectric facilities, totaling more than 200 MW.
Other Provisions
The plan also outlines roles for:
hydrogen, which could constitute 12 to 18% of energy use in the country by 2050 under “supportive policy measures or key input cost reductions.”
energy efficiency, which is earmarked for $10.9 billion in spending over 12 years, “nearly three times [the] historical annual investment.”
pumped storage: The government is supporting predevelopment work for the proposed Ontario Pumped Storage Project, which would provide up to 1,000 MW. OEB is directed to consider changing its rate regulation to support such “long-life” electricity projects.
storage: The province will add nearly 3,000 MW of energy storage to supplement intermittent renewable generation.
interconnections: The government is using authority under the 2024 Affordable Energy Act to reduce the capital costs for residential developers and industrial customers connecting to distribution and transmission infrastructure. “These changes will help unlock new developments by reducing investment risk for ‘first mover’ customers, while ensuring fairness is maintained for ratepayers,” the plan says. Draft regulations will be posted for public comment in summer 2025.
distribution systems: The plan defines grid modernization, directing Ontario’s 59 LDCs to make upgrades that allow them to respond more quickly to outages, improve efficiency, and support two-way power flows and real-time system monitoring to accommodate DERs.
National Energy Corridors for clean energy, transmission and pipelines: “This includes exploring opportunities to build the critical infrastructure needed to move energy and resources east-west across Canada and north to tidewater, including through new transmission lines, pipelines, rail networks and a potential deep-sea port on James Bay.”
Transmission
The plan outlines additions to Ontario’s 18,600 miles of high-voltage transmission, calling for expanding its north-south “electricity backbone” to reduce constraints preventing generation sites in the north from delivering to loads in the south. In total, IESO has about 1,500 kilometers of new transmission lines “under development or planned,” according to IESO CEO Leslie Gallinger.
The plan supports the 500-kV Barrie-to-Sudbury single-circuit line, due in service in 2032. “Because of the critical system value to this strengthened corridor, the IESO has also recommended initiating early development work on a second 500-kV line,” the plan says.
IESO also has recommended reconductoring the 230-kV Orangeville-to-Barrie line.
The two projects are “critical enablers” for future generation projects such as the proposed Nine Mile Rapids and Grand Rapids hydropower stations, the plan says.
IESO also has identified two major projects in the Greater Toronto Area (GTA): reconductoring the 115-kV Manby-Riverside line, due to bein service in 2026; and a new double-circuit 500-kV line from Bowmanville Switching Station to an existing 500-kV station in the GTA. The line, expected in service in the early 2030s, would connect OPG’s SMR units 2, 3 and 4 at Darlington to the grid and send additional electricity to the GTA.
The ministry ordered IESO to recommend by August an option for additional transmission into Downtown Toronto to support growth and electrification. “Once IESO makes a recommendation, the government intends to act quickly to kickstart development, so it can be delivered in the early-to-mid 2030s,” the ministry said.
The government has authorized Hydro One to make advance purchases of up to five 750-MVA, 500/230-kV autotransformers to be deployed in the GTA and in southwest and northern Ontario.
Streamlining Regulation
The ministry called for streamlining provincial approval processes for “priority energy projects that are essential to supporting housing, job creation and long-term economic security.”
The province is creating a “One Team” initiative to accelerate approvals of “strategically important” energy projects, starting with projects in IESO’s Long Term 2 procurement. (See related story, IESO Purchasing 3,000 MW of Energy and Capacity.)
In 2022, the government exempted transmission lines wholly funded by commercial, industrial or generator customers from requiring Leave to Construct approval from the OEB. In 2024, the government moved all transmission projects into Ontario’s Class Environmental Assessment process, which is expected to reduce development timelines for large projects by up to two years.
The government ordered IESO and OEB to review their approval, connection, procurement and regulatory processes and report back on ways they can reduce duplication, shorten timelines and improve efficiency.
“Complex permitting and regulatory processes across multiple ministries and levels of government can create barriers, delays and added costs for projects that are critical to the province’s growth and competitiveness,” it said.
RENO, Nev. — Out-of-state wind integration, merchant transmission development and the WestTEC planning effort are all factors influencing CAISO’s interregional transmission planning.
Neil Millar, CAISO’s vice president of infrastructure and operations planning, gave a briefing on the ISO’s West-wide transmission activities during the June 18 meeting of the Western Energy Markets Governing Body.
CAISO’s previous three transmission plans included $5.8 billion in projects on average, which largely were policy-driven projects to support access to resource basins, Millar said. But projects in the 2024/25 plan are focused mainly on reliability in the face of surging load growth.
Millar said last year’s transmission plan was based on load growth of about 1% per year, while the load growth in this year’s plan was about 1.6%. CAISO now is looking at a load growth rate of about 2.5% for next year’s plan.
“The increased rate of load growth reflected in the most recent load forecast associated with building and other electrification, data center growth and transportation electrification results in significant reliability-driven needs in this year’s transmission plan,” the 2024/25 plan stated.
Out-of-state Wind
Accessing out-of-state wind continues to be a focus for the ISO. Millar said CAISO’s base case scenarios call for seeking more than 5,500 MW of Wyoming and Idaho wind resources and more than 3,600 MW of New Mexico wind.
He said CAISO is working with its neighbors to explore potential coordination on specific projects or to leverage merchant projects that might be moving forward.
And supporting the Western Transmission Expansion Coalition (WestTEC) effort is a priority for CAISO, according to Millar.
The WestTEC effort, jointly facilitated by the Western Power Pool and WECC, will address long-term interregional transmission needs across the Western Interconnection. The goal is to produce transmission portfolios for 10- and 20-year planning horizons.
WestTEC expects to release its initial 10-year horizon report in August, according to a June 12 presentation to the group’s Regional Engagement Committee. The group projects that the 20-year horizon report and the final 10-year report will be completed by September 2026. (See WestTEC Tx Study on Track Despite Delays.)
For Millar, the key advantage of WestTEC is that it will create an “actionable” plan. He said it’s one of the first studies based on extensive input from load-serving entities about their resource plans, particularly in its 10-year horizon.
CAISO will use the information to help identify opportunities it will emphasize, either by itself or in collaboration with other entities.
“At this point, I’m not in a position to tell you which projects we’re throwing our weight behind, because we are looking to see what falls out from the WestTEC effort first before we move to that next stage,” Millar said.
The PJM Markets and Reliability Committee discussed a problem statement and issue charge brought by Pennsylvania Gov. Josh Shapiro (D) to open a discussion on establishing a sub-annual capacity market design.
Presenting the proposal to the committee on June 18, Deputy Secretary of Policy Jacob Finkel said the issue charge calls for a senior task force to be established to work toward a seasonal design with the aim of PJM filing a proposal at FERC in the first quarter of 2026. That timeline targets implementation in the 2029/30 Base Residual Auction (BRA), which Finkel said is a tight timeline but an important goal for fixing an annual capacity market design that overcharges ratepayers and blunts market signals.
Christian McDewell, of the Pennsylvania Public Utilities Commission, said the commonwealth supported a seasonal design during the 2023 Critical Issue Fast Path (CIFP) process focused on long-term resource adequacy. He recognized, though, that more work was needed to arrive at a workable proposal. (See PJM Stakeholders Vote Against All CIFP Proposals.)
“I think that it’s a good thing to look at this. We’ve been moving in fits and starts … toward what looks like a sub-annual market,” he said.
Several stakeholders expressed skepticism that such a major market overhaul can be completed in six months.
Paul Sotkiewicz, president of E-Cubed Policy Associates, said past CIFP processes and the implementation of effective load-carrying capability for resource accreditation have shown what happens when stakeholder deliberations are accelerated. While developing a seasonal market design is a great idea, he said it likely would take at least two years to get right.
PJM Vice President of Market Design and Economics Adam Keech said February is the latest PJM could make a filing with the expectation that FERC could issue a favorable order in time for the 2029/30 BRA pre-auction. That assumes there are no deficiency notices. There also would be a non-trivial amount of time needed for software development and testing to effectively split the capacity market in half.
Asked if the implementation could be done in a phased approach, Keech said that would need to be done logically to not have a “Frankenstein” transition period.
Middle River Power’s Sophia Dossin said MISO moved recently to a four-season auction after a considerably longer stakeholder process and still had a rocky implementation. She questioned whether the governor’s office is open to making sure the timeline does not supersede the quality of the product.
Finkel responded that the commonwealth sees implementation in the 2029/30 auction as an important goal but does not want to put the timeline over all else. Getting started is what’s most important, he added.
He said a seasonal market was discussed in 2006 and 2018, as well as during the 2023 CIFP process, making it frustrating that it’s viewed as something that will take an extended period of time.
NRDC Senior Advocate Tom Rutigliano said the energy landscape is changing rapidly, but PJM has difficulty adjusting its capacity market on an agile timeline. It takes time for processes to work their way through the stakeholder process, the commission and then be implemented in a forward auction. If PJM does not become more responsive, he said, it will continue to operate between crises.
Susan Bruce, representing the PJM Industrial Customer Coalition, said consumers are concerned about many of the same issues as the commonwealth. Implementing a seasonal market could affect other market components in ways that are difficult to predict at the onset, she said. She compared the capacity market to a tapestry in which pulling on one thread affects the larger design.
While there have been a lot of studies on how a sub-annual market could function in PJM, Bruce said much of that work was done at a time when PJM had excess capacity.
“What does a seasonal construct look like in a world where we are tight all four seasons?” she asked.
Vitol’s Jason Barker said he’s worried about the implications of a problem statement that includes value statements about the potential cost impact of shifting to a seasonal auction when it is not known how such a change would affect pricing.
Finkel said the commonwealth is less concerned about the dollar amount than it is about ensuring the market accurately reflects what is happening in the real world.
Representing the PJM Public Power Coalition, Customized Energy Solutions’ Carl Johnson said PJM presented a capacity market design road map in July 2024 showing concurrent work on a more granular market and possible rethinking of the forward auction. He said it would make sense for the two issues to be discussed together to arrive at a holistic solution.
Finkel responded that both are important issues, but the Reliability Pricing Model is not as effective as it could be with an annual design, which is a discrete topic he said other RTOs have managed to address.
Exelon’s Alex Stern lauded the governor’s office for bringing the proposal, saying everyone benefits when the member states are involved in the stakeholder process. Throughout his time participating in PJM, he said this is the first time he can recall a state bringing its own issue charge and being involved in this manner. While it may not be possible to arrive at a proposal in time for the 2029/30 auction, he said it’s worthwhile to try.
“Even if it’s not all four seasons … a seasonal market design, in my mind, can better reflect the actual seasonal variations in supply,” Stern said.
Rory Sweeney, of the Northern Virginia Electric Cooperative, questioned whether the governor’s office would be satisfied if the stakeholder process resulted in support for the status quo. Finkel responded that it’s important to let that process play out and see where the membership lands. The outcome could be viewed differently if there is broad support across all sectors or a divided stakeholder body.
Ontario’s first-ever integrated energy plan includes a long “to do” list for grid operator IESO.
Unlike single-state ISOs in the U.S., which maintain some independence from their state governments and are regulated by FERC, IESO is a wholly government creation, answering to Ontario through the Ministry of Energy and Mines and the Ontario Energy Board (OEB).
The difference is stark. In support of its 152-page energy plan, the ministry on June 12 also issued a prescriptive 12-page directive spelling out in detail how the ISO is to carry out its policy, with sections on planning, district energy systems, distributed energy resources, transmission, low-carbon hydrogen strategy, hydro and nuclear generation, and export opportunities.
It listed 11 “report-backs” e.g., a Dec. 31 deadline for a report on “opportunities to streamline energy related lESO-Ied procurement processes.”
Although the ministry’s plan says IESO will continue to lead the development of electricity demand forecasts, it said it must work with the OEB to develop “a formal process to engage natural gas distributors in regional electricity planning activities.” (See related story, Ontario Integrated Energy Plan Boosts Gas, Nukes.)
“IESO, electricity utilities and natural gas distributors — under the direction of the OEB — will be required to develop coordinated, best-practice scenario modeling to assess future energy needs across fuels as appropriate,” the ministry said. “This will improve systemwide consistency on planning assumptions and investment priorities.”
The plan directs IESO to ensure its planning supports “long-lead” energy projects such as long-duration storage and new nuclear and hydro projects.
It also requires IESO to expand the mandate of its Strategic Advisory Committee to “reflect the province’s broader economic and community priorities” and to increase the panel’s membership to include real estate developers, transit agencies and manufacturers. The ministry said technical standards and safety organizations in the province, such as the Electrical Safety Authority and the Technical Standards and Safety Authority, also will participate in SAC meetings. (See What to Know About IESO.)
In a statement at the plan’s release, IESO said it “appreciates the opportunity to be tasked with leading a number of key components that will help meet the province’s growing needs.”
In a June 23 speech to the Ontario Energy Network, IESO CEO Lesley Gallinger said the grid operator was responding to the plan by “moving faster to build bigger, leveraging the ‘no regrets’ actions already in motion to make smart investments in new infrastructure.”
The ISO also is “implementing a customer-oriented and affordability-minded approach to drive down costs and make it easier for businesses to connect to the grid,” she added. “One of the changes I am most excited about is the ‘concierge-style’ approach we are implementing to ensure customers understand where and how to connect, while streamlining and simplifying our processes so that we can guide customers from start to finish.”
Ontario says it hopes to expand its electricity exports to the U.S. “once Canadian-American relations normalize.” | Ontario Ministry of Energy & Mines
Economic Development
Economic development is a recurrent theme in the plan, which calls for making the province “a global clean energy superpower” that exports electricity, nuclear technology, medical isotopes and engineering expertise.
The ministry has proposed legislation requiring IESO and the OEB to “embed economic growth as a priority.”
“Integrated planning will be supported by independent, external advice on how best to align energy decisions with broader government priorities — such as housing, economic development and competitiveness,” it said.
The government also ordered IESO to create a Major Project Identification Committee for each planning region as “an early warning system … [to] ensure that major housing, industrial and infrastructure projects that could impact electricity demand are identified early and fully accounted for in high-growth demand forecasts.”
The committee will include the ministries of energy, economic development and housing, in addition to local and regional economic development agencies and municipalities and Indigenous communities.
“Municipal governments — who plan for land use, housing and economic development — must be better connected to the province’s electricity and fuels planning processes,” the plan says.
The government also directs OEB, IESO and other stakeholders to identify improvements to regional and bulk planning processes to “better match the pace of load growth.”
Export Potential
Between 2021 and 2023, Ontario exported more than 40 TWh of electricity to the U.S., about 9% of Ontario’s total annual generation. In addition to displacing higher-emitting generation in the U.S., the exports have generated $400 million to $700 million annually.
Noting that both NYISO and MISO have warned of growing capacity deficits as fossil fuel plants are shuttered, the plan calls for increasing those exports “once Canadian-American relations normalize.” To that end, Ontario and IESO are evaluating transmission upgrades to move power from generators to existing and potential new interties.
Costs
The plan makes frequent reference to the government’s efforts to control electric costs, which it says are at or below the rates in the U.S. Great Lakes states. (See related story, IESO Purchasing 3,000 MW of Energy and Capacity.)
On April 1, the Canadian government eliminated the previous government’s consumer carbon tax on natural gas and gasoline, which is expected to save Ontario households more than $700 annually.
“Ontario’s plan to meet growing energy demand while reducing emissions does not and will not include a carbon tax,” the plan says.
Continuing Ontario’s efforts to replace costly contracts signed under the previous government, IESO announced it has signed contracts with 27 natural gas and wind generators.
In its second medium-term procurement (MT2), the ISO agreed to purchase 2,006 MW of natural gas-fired capacity ranging from $450 to $795/MW-business day beginning in May 2026 and 2029. The weighted average price was $598/MW-business day.
It also agreed to buy 963 MW from 16 wind generators at prices ranging from $60/MWh to nearly $125/MWh, plus 24 MW of biomass ($204.94/MWh) and 7.82 MW of landfill gas at two sites for $110/MWh and $150/MWh. The weighted average price for all renewables was $79.55/MWh.
IESO said the energy projects were priced 21% below their previous contracts. Although capacity costs were higher than in the ISO’s first medium-term procurement (MT1), the Ontario Ministry of Energy and Mines said the costs were 65% below the costs of building new gas-fired generation.
“This success stands in sharp contrast to the fixed, above-market contracts signed by the previous government, which locked Ontario into long-term costs well above market prices,” the ministry said in its integrated energy plan, released in June. (See Ontario Integrated Energy Plan Boosts Gas, Nukes.)
The Progressive Conservative Party has ruled Ontario since ousting the Liberal Party government in 2018. Between 2004 and 2016, the Liberal government signed more than 33,000 contracts, some at up to 10 times market rates and for as long as 20 years, according to the ministry. It criticized what it called “an ideologically driven energy agenda that prioritized over-market, expensive, intermittent generation at a time when it wasn’t needed.”
MT2 RFP results | IESO
MT2 sought to procure existing energy and capacity resources that are uncontracted or coming to the end of their contracts in the next four years. The winners received five-year contracts beginning on May 1 of either 2026, 2027, 2028 or 2029.
“Medium-term [requests for proposals] provide resources greater certainty through longer forward periods and flexible five-year commitments, as compared to the annual capacity auction, while ensuring the IESO is not locked into commitments that are no longer reflective of changing needs,” the ISO said.
Eligibility
Biofuel, electric storage and gas facilities were eligible for capacity contracts; biofuel, solar and wind generators were invited to seek energy contracts.
Dispatchable loads and demand response resources were excluded and instead invited to enter IESO’s annual capacity auction. The ISO will outline potential changes to the capacity auction, including a revised tie-break methodology, on June 26.
The ISO said MT2 gave generation owners not ready to invest in repowering their facilities for the Long-Term 2 (LT2) Energy solicitation more time to prepare proposals for the future LT3 RFP with a contract in place.
1st Procurement
In MT1 in 2022, IESO agreed to acquire 757 MW of nameplate capacity wind and natural gas (309 MW summer UCAP) at prices ranging from $265 to $470/MW-business day (UCAP).
One of the successful bidders in MT1, Atlantic Power’s Nipigon Generating Station, also won a contract in MT2, seeing its price rise from $250 to $449.98, an 80% increase.
IESO spokesman Andrew Dow said he could not say why Atlantic Power bid so much higher in MT2 than in MT1. But he said the ISO’s “general expectation” is that owners of older generators structure their bids “to make sure that they are recovering enough to help [fund] whatever investments or upgrades are needed to keep their facility running for longer.”
The 40-MW Nipigon plant has been operating for 33 years.
The ISO said future medium-term RFPs will reflect system needs and “will likely see increased resource eligibility and competition, including the possible inclusion of new-build resources.”
Future Procurements
Ontario already has contracted for more than 3,300 MW of new capacity, including battery storage, natural gas and biogas, through the Expedited Long-Term (ELT) and LT1 procurements.
The ministry said LT2 will be the largest electricity procurement in the province’s history with a shopping list for up to 14 TWh/year of new energy, equivalent to about 6,000 MW of capacity. The solicitation will be open to energy storage, wind, solar, biomass, biogas, natural gas and energy from waste.
LT2 also will seek 1,600 MW of new capacity resources. Projects will be phased in through four annual intake windows, with in-service dates expected by 2034.
The Ontario Ministry of Agriculture, Food and Agribusiness (OMAFA) and the Ministry of Natural Resources (MNR) will conduct a joint webinar on the LT2 procurement on June 25. MNR will discuss requirements for renewable energy on Crown land. OMAFA will discuss rules for energy projects in prime agricultural areas. The deadline for the first solicitation is Oct. 16.
The province has directed IESO to report back on options for a separate procurement stream for “strategic long-lead projects” such as new hydroelectric generation and long-duration energy storage.
“This stream would help ensure Ontario can continue to plan and diversify its supply mix with assets that support long-term reliability and system flexibility,” the ministry said.
ISO-NE CEO Gordon van Welie has announced plans to step down at the end of 2025. He will be replaced by longtime ISO-NE COO Vamsi Chadalavada.
“I have been fortunate to spend 25 wonderful years at the ISO,” van Welie said in a statement. “I’m extremely proud of what we’ve accomplished, from a startup organization to a sophisticated company with world-class people, systems and processes that is well positioned to help the region navigate an increasingly complex energy environment.”
Van Welie is by far the longest-serving CEO of any RTO or ISO, having led ISO-NE for most of its history. He has overseen ISO-NE’s transition to becoming an RTO, the launch of its capacity market, the shift in the region’s generation mix from coal and oil toward natural gas, and multiple overhauls of its wholesale electricity markets.
In the retirement announcement, van Welie said the region’s supply and demand outlook should remain “relatively stable through the next several years.” The ongoing overhaul of the capacity market and anticipated longer-term changes in the region’s resource mix and load profile make this “an appropriate time to step aside and allow new leadership to steer the path forward.”
Cheryl LaFleur, chair of the ISO-NE Board of Directors, applauded van Welie on his time with the RTO and said he has “led the ISO through significant transformation, building a strong team of professionals who keep the lights on and run the markets for our region.”
Vamsi Chadalavada | ISO-NE
“I know Gordon will be missed greatly at the ISO and across the New England region,” LaFleur added.
“Gordon van Welie is an institution,” said Dan Dolan, president of the New England Power Generators Association. “Gordon has been a thoughtful, innovative and tireless leader for the region. His candor and willingness to engage in difficult, but necessary, conversations is a testament to his commitment to doing what is right for New England.”
Chadalavada, who is slated to take over for van Welie at the beginning of 2026, has worked for ISO-NE since 2004 and has served as COO since 2008. As the RTO’s second in command, he oversees the operation of the power system and market operations, along with system planning. Like van Welie, Chadalavada worked as a vice president for Siemens Power Transmission and Distribution before joining ISO-NE.
“We are very fortunate to have someone with Vamsi’s leadership, experience and qualifications ready to take on the role,” LaFleur said. “His appointment demonstrates our strong confidence in his ability to lead the organization through the grid transition ahead.”
Reacting to the news, ISO-NE stakeholders commended van Welie on his tenure and retirement and emphasized the major role he has played in ISO-NE’s evolution. Industry members also praised the selection of Chadalavada as the next CEO, saying he’s well prepared to take the reins.
“NEPOOL would like to congratulate Gordon on the announcement of his upcoming retirement,” NEPOOL Chair Sarah Bresolin said. “During his tenure, NEPOOL has benefited from his intellect and dedicated service. Gordon leaves the region in a strong position.” Bresolin applauded Chadalavada’s appointment, which she said leaves the region “in very good hands.”
Alex Lawton of Advanced Energy United said Chadalavada “is the right person for the job, and we are confident he will work diligently and collaboratively with stakeholders and the New England states to navigate the evolution of our grid.”
Joe LaRusso of the Acadia Center said van Welie’s retirement comes at a “pivotal moment” for ISO-NE, with power demand likely to grow after a long period of stability, intermittent renewables set to come online, and increasing conflicts between state and federal energy policy.
“I expect the transition from Gordon to his successor Vamsi Chadalavada to be a smooth one,” LaRusso said, adding that Chadalavada “is well aware of all of the challenges facing the ISO and will certainly see current initiatives such as capacity market and reliability reforms, and Longer-Term Transmission Planning and FERC Order 1920 compliance through to completion. The ISO won’t deviate much, if at all, from its current path, and Gordon’s stamp will inevitably remain imprinted on ISO New England for some years to come.”
The Northwest Power and Conservation Council has hired Peter Cogswell, the former director of intergovernmental affairs at the Bonneville Power Administration, as its next executive director.
Cogswell will assume the position on July 7, succeeding Bill Edmonds, who stepped down as executive director in April after serving for five years with the council, according to a June 23 news release.
Council Chair Mike Milburn said in a statement that Cogswell “is an experienced leader with an impressive energy policy background who is deeply connected to the region.”
“We’re confident that Peter will be able to hit the ground running at this critical time as we ramp up our work on the next Columbia River Basin Fish and Wildlife Program and Ninth Northwest Regional Power Plan,” Milburn added.
The council is required under the Northwest Power Act “to develop a plan to ensure an adequate, efficient, economical and reliable power supply for the region.” NWPCC publishes a plan every five years, with the next plan slated for release in 2026, according to the council’s website.
For example, the council’s initial 20-year forecast found that electric vehicles and data centers could bring annual energy demand in the Pacific Northwest to 31,000 and 44,000 aMW by 2046 — up from an average of approximately 22,000 aMW during the past several years.
The council also is considering updating models used in the 2021 power plan after Trump rescinded several clean energy initiatives implemented under former President Joe Biden.
Cogswell brings decades of experience from the energy industry to the council.
According to his LinkedIn profile, Cogswell joined BPA in October 2007 and served as council liaison and the agency’s director of intergovernmental affairs until January 2022. During his time with BPA, Cogswell helped develop two of the council’s power plans.
After leaving BPA, Cogswell assumed the role of director of government and external affairs at renewable energy developer Simply Blue.
The release also notes that Cogswell worked at PacifiCorp and as deputy chief of staff and policy advisor to former Oregon Gov. Ted Kulongoski. While in the governor’s office, Cogswell “led efforts to adopt several early clean energy policies, including Oregon’s first renewable energy standard,” according to the release.
“I am very fortunate to have engaged extensively with the council over the course of my career,” Cogswell said in a statement. “I am excited about the opportunity to build on that experience by working with members, staff and a broad group of partners, including tribes, states, utilities and advocates, to ensure the council continues its important work in the region.”
The NWPCC is an interstate group with representatives from Idaho, Montana, Oregon and Washington, and works with regional partners, including the Bonneville Power Administration, the U.S. Army Corps of Engineers and the Bureau of Reclamation, as well as with FERC, to implement its plans and programs.
