The NYISO Business Issues Committee and Operating Committee approved without objection governing document revisions that would implement transmission owners’ right of first refusal in the ISO’s planning processes at their meetings June 16 and 20, respectively.
FERC in 2021 ruled that New York TOs have a federal ROFR over transmission upgrades to their facilities and in 2022 approved tariff revisions implementing a ROFR for those that are part of another developer’s public policy transmission project under Order 1000. (See FERC Approves ROFR for NY Transmission Upgrades.)
But those revisions did not include projects selected by NYISO’s own reliability and economic planning processes that include ROFR-eligible upgrades. The approved proposal would revise tariff attachments P, Y and FF to implement that.
The proposal now goes to the Management Committee for its June 30 meeting. If approved by the MC and the Board of Directors, NYISO anticipates filing with FERC in July.
Other BIC Action
The BIC also passed a pair of motions unanimously.
Stakeholders also passed a motion to recommend approving changes to the tariff to implement the Market Purchase Hub Transactions project. The market design would allow trading hub energy owners (THEOs) to purchase and sell power on the NYISO day-ahead market to settle imbalances.
System Impact Studies
The OC also unanimously passed a pair of system impact study reports for two interconnection studies.
One of these, the POWI Project, would draw 50 MW continuously to the Port of Coeymans to support the port’s upgrades to service the offshore wind industry. (See Siemens Gamesa Plans OSW Nacelle Factory in Upstate NY.) The SIS found there would be no adverse impacts on the local grid. The good-faith cost estimate for the necessary upgrades was found to be $76.48 million.
The other study was for Beowulf Energy’s Cayuga Compute project, a large data center expansion at the site of a retired coal plant. The project will boost the data center’s load from 50 MW to 138 MW.
The data center supports artificial intelligence computation. The SIS found that the project could cause thermal and voltage violations but they could be mitigated with operating procedures and several upgrades to the local grid. Combined, the local upgrades would cost about $15 million.
New York’s governor has directed the state power authority to develop an advanced nuclear facility with at least 1 GW of nameplate capacity.
The move is intended to bolster the state’s lagging clean energy efforts while simultaneously injecting a large quantity of emissions-free baseload power into the grid to facilitate decarbonization and economic development.
In her announcement June 23, Gov. Kathy Hochul (D) did not elaborate on details about the facility to be built. The New York Power Authority clarified later that no determination has been made on the reactor technology to be used.
The move places Hochul in an increasingly large group of industry, government and policy leaders hoping to advance a nuclear renaissance in the United States.
It also places her squarely in the crosshairs of nuclear power’s many remaining opponents, a fact the governor alluded to when she said: “I’m the first Democratic governor in a generation to say to nuclear, ‘I’m embracing this. My state will embrace this.’”
On cue, opponents raised questions about the plan or attacked it outright, as they have criticized the administration’s increasing willingness over the past few years to consider new nuclear generation. (See N.Y. Takes a Closer Look at Advanced Nuclear.)
In January 2025, New York joined Constellation Energy in an application to the U.S. Department of Energy for a grant to support co-locating one or more advanced reactors with the two existing reactors at Nine Mile Point on the south shore of Lake Ontario.
Hochul said this new initiative builds on that collaboration and sets the stage for collaboration with other states and with Ontario — North America’s first small modular reactor is being built in Canada, on the lake’s north shore. (See Ontario Greenlights OPG to Build Small Modular Reactor.)
The new nuclear project would be built in partnership with the private sector in a community that welcomes it, Hochul said. The state wants to help finance the plant and buy the power it generates, she said, and she is directing the Department of Public Service to work with NYPA to protect ratepayers.
Important Role
New York’s four operating commercial reactors, all owned by Constellation, receive ratepayer-funded subsidies in recognition of their value in providing 21% of the state’s electricity with zero carbon emissions.
Nuclear opponents pounce on such subsidies (here and in other states) and point to the fantastically high cost of recent reactor construction projects as proof that nuclear is uneconomical — in addition to being potentially dangerous.
Levelized cost of energy comparisons do show that new-build nuclear is several times more expensive than new-build solar and wind farms of the type proposed across upstate New York. (See Lazard: Solar and Wind Retain Lowest LCOEs.)
But the levelized value of electricity is harder to quantify.
NYISO shows a very low capacity factor for New York solar — 16% for front of the meter and 12.7% for behind the meter for 2023. Onshore wind was much higher in 2023, but still only 22%.
Extensive backstops would be needed for any whole reliance on photovoltaics and wind turbines to power the Empire State, likely at considerable cost.
In contrast, the Nine Mile Point reactors, which are 37 and 55 years old, ran at a capacity factor of 92.8% in 2023, and the 50-year-old Fitzpatrick reactor operated at 99.9%.
Further, New York’s efforts to encourage wind, solar and storage construction are lagging for a host of reasons. The state expects to miss the first milestone in its 2019 climate law — 70% renewable energy by 2030 — perhaps by a wide margin.
New York stood at just 23.2% renewables in 2023, due in part to the shutdown of the Indian Point nuclear reactors in 2020 and 2021. (See NY Quantifies Slow Progress Toward Renewables.)
Hochul mentioned this as she spoke June 23 about the new initiative and flagged the shortcomings of wind and solar.
“It shouldn’t be this hard. But no matter how hard we fight for renewables, solar works when the sun is shining, wind turbines spin when the air is moving,” she said. “We need electricity that’s reliable all day long, regardless of the weather outdoors.”
That would be fossil fuel or nuclear, and New York is not going to add fossil generation, she said.
Criticism Lobbed
Hochul’s comments on the state’s clean-energy transition have been more pragmatic than dogmatic, particularly when ratepayers are at risk of bearing higher costs.
She put on hold the plans for the state’s cap-and-invest system, for example, and she echoed some of President Trump’s speaking points in her June 23 comments, saying the federal nuclear regulatory process was too slow and too cumbersome. (See NY Defers Action on Controversial Cap-and-invest.)
State Sen. Liz Krueger (D), chair of the Senate Finance Committee, shared questions about Hochul’s announcement that likely were shared by many nuclear skeptics and opponents: Is it the most cost-effective option? Can it be completed quickly? What will happen to radioactive waste? Are there alternatives? Will local governments be allowed to consent or refuse?
“I have yet to see any real-world examples of new nuclear development for which all of these questions can be answered in the affirmative,” Krueger posted on X.
Others took issue with the role to be played by NYPA, which was given expanded authority to develop renewables but debuted with a 3-GW plan that carried a high expected rate of attrition, far short of the robust 15-GW vision advocates had sought. (See NYPA Finalizes Road Map for Renewables Development.)
“NYPA has the power and mandate to build 15GW of renewables and should not let Trump promises lead New Yorkers away from it,” Public Power NY said. “After appointing a Republican to lead NYPA while remaining silent on its mandate to build wind and solar, Hochul’s decision to step in based on promises from Donald Trump shows just how unserious she is about New Yorker’s energy bills and climate future. NYPA should be laser-focused on rapidly scaling up their buildout of affordable solar and wind, which is the only way to meet the state’s science-based climate goals and lower energy bills.”
Others were more enthusiastic about Hochul’s announcement, including business and organized labor leaders. Hochul estimated the new advanced nuclear facility would create 1,600 construction jobs and 1,200 permanent jobs.
The plant would be upstate, much of which is economically stagnant and has been losing population for generations.
Hochul spoke not far from her childhood home, and noted she was the only one of six siblings who did not leave the state to start her career. A wind farm now stands where her father and grandfather once worked in a steel mill.
Part of the goal with the nuclear project is to provide the power for new economic development, she added.
State Sen. George Borello (R) applauded the plan and suggested the former NRG coal-fired plant on the shore of Lake Erie be prioritized as a site. Its shutdown left a gaping hole in the economy and budget of the city of Dunkirk, he said.
“This would bring back critical revenue, generate well-paying jobs and deliver the long-overdue economic recovery that Dunkirk desperately needs,” he posted on Facebook.
Constellation also welcomed Hochul’s June 23 announcement with enthusiasm but without specifics on next steps.
A previous version of this story misstated the number of commercial reactors now in operation in New York.
[EDITOR’S NOTE: An earlier version of this story implied that there was an error regarding MISO’s risk in NERC’s Summer Reliability Assessment. It has been corrected to say that the error was in the Long-Term Reliability Assessment.]
Legal challenges to the U.S. Department of Energy’s order to keep the J.H. Campbell power plant in Michigan open mounted with appeals of the initial order and comments at the case in front of FERC on how to pay for it. (See Consumers Energy Seeking Compensation for Keeping Campbell Open.)
Michigan Attorney General Dana Nessel filed a request for rehearing at DOE on June 18 and intervened in the FERC docket (EL25-90) on June 20.
“The closure of this coal-powered electric plant has been planned for years; the utility made all due preparations to maintain our energy load without it; and the closure has been agreed to and cited in settlements affecting customer costs,” Nessel said in a statement. “In particular, if this arbitrary and unlawful order is allowed to stand, the only effect Michiganders will feel will be the pinch in their pockets. The costs of maintaining production at the plant, long since prepared for closure, could be an enormous burden on the ratepaying customers of Consumers Energy.”
The rehearing request her office filed argued the Campbell order “is an unlawful abuse of the department’s emergency authority” that it previously used only in response to natural disasters and requests from grid operators or other governmental bodies. Claims that keeping the plant running this summer responds to an emergency “cannot even bear the mildest scrutiny.”
Nessel also argued that MISO has found it has enough power to meet demand this summer. NERC did place the region under “elevated risk” in its Summer Reliability Assessment, but the attorney general said that was not even its highest level of risk in the report, and MISO has gotten that label regularly in reliability assessments this decade. MISO’s anticipated reserve margin this summer beats its target and is higher than it has been most of this decade, she said.
“The order indicates that the department believes it has the authority to decide which power plants may retire and when, not based on the kind of real emergency that has justified past action, but rather based on its own policy preferences,” Nessel said. “The department appears to want to place its own judgment about operating reserve margins ahead of MISO’s, and its own preference for which resources are employed to maintain resource adequacy ahead of Michigan’s.”
NERC mistakenly labeled MISO at “high risk” in its Long-Term Reliability Assessment based on what it called “mismatched data” from the RTO and said it should be reclassified as “elevated risk” for 2025-2027. The ERO admitted the mistake after criticism from Independent Market Monitor David Patton, who argued the report influenced DOE’s decision to keep Campbell open. (See NERC Responds to MISO IMM’s LTRA Criticism.)
Earthjustice, Sierra Club, the Natural Resources Defense Council, Public Citizen and other groups filed a separate rehearing request at DOE.
“The order is based on a profoundly incorrect understanding of the handful of sources it selectively quotes,” the groups said. “Those sources, and the order itself, do not support the order’s claim of a resource adequacy emergency in any of the various locations at which the order ambiguously gestures.”
Keeping the plant running at this point will be costly because Consumers deliberately minimized investments in it in recent years as it was expected to be retired, they argued. Getting it running could cost tens of millions of dollars, they said.
The same groups made a joint filing at FERC, where the only issue before the commission is who will pay for the power plant. The validity and sufficiency of the order will be addressed through pending requests for rehearing at DOE and, “potentially, litigation thereafter.”
“The commission lacks a basis to determine which, if any, utility ratepayers will materially benefit from the Campbell plant’s operation pursuant to the department’s order,” the groups said. “Ratepayers in Michigan, Iowa, Missouri, Wisconsin and other MISO states have met, and are already paying for, their resource adequacy obligations under MISO’s commission-approved framework for the order’s period.”
They argued consumers in MISO already have secured sufficient resources for this summer, so none of them would be clear beneficiaries of keeping the coal plant open, which means FERC cannot assign costs at this time. The environmental and consumer groups asked FERC to deny the complaint or to hold off ruling on the request for now.
The RTO itself weighed in on the FERC case, saying that while it does not intend to challenge DOE’s order, it has procured enough capacity for this summer’s demand. It has worked with its members, market participants, state regulators and FERC to ensure reliability going forward.
“MISO continues to work with these parties in the context of anticipated growing demand for electricity, planned electric generating facility retirements and an evolving mix of new electric generating resources to refine processes that address the challenges ahead,” it said. “MISO is confident that these collaborative efforts do not require further intervention and will help ensure the region continues to procure sufficient capacity to meet demand.”
But the order is in effect, and MISO lacks any current rules to allocate the costs of keeping the plant running, it said.
Northern Indiana Public Service Co. said that while Campbell is the subject of the proceeding at FERC, DOE already has used its emergency powers in PJM and could use them for other plants. NIPSCO supports Consumers’ request, but DOE’s ongoing use of the authority sheds light on the need for a more universal fix in MISO’s tariff.
FERC should direct MISO to come up with more universal rules on cost recovery so it does not have to deal with future requests in a “piecemeal fashion,” NIPSCO said. “The circumstances that Consumers Energy has found itself in may very well present themselves to other generators in the MISO region, and without an appropriate rate recovery mechanism, MISO’s existing tariff may be unjust and unreasonable.”
Tenaska Power Services and the Texas Public Utility Commission have reached a settlement in which the company will pay a $353,500 penalty and disgorge $28.24 million in excess revenue made in the ERCOT market in violation of agency rules.
The commission consented to the penalties during its June 20 open meeting (57437).
The PUC’s Compliance and Enforcement staff recommended the action after investigating Tenaska Power’s assignment of ancillary services (AS) from January 2016 through April 2021. Staff said Tenaska, a qualified scheduling entity (QSE) and ERCOT market participant, assigned the services to unqualified load resources.
“Tenaska Power was paid to keep capacity available to provide ancillary services during this period but was incapable of providing the ancillary services assigned to unqualified load resources,” staff said.
The investigation found four separate events where Tenaska Power was at fault:
In 2018, two separate load resources under common ownership were provisionally authorized to provide AS responsibilities for a 90-day period. After a clerical oversight, Tenaska Power continued to assign the responsibility to the unqualified load resources after their provisional authorizations had lapsed. During the 31 days that followed, the resources were inadvertently assigned AS responsibilities for 5,261 intervals.
In January 2018, the company telemetered an incorrect resource status code as the QSE for a third party’s generation resource. That led to ERCOT issuing a reliability unit commitment instruction for a unit that was unable to fulfill the request.
During Winter Storm Uri in February 2021, Tenaska Power received real-time off-line reserve price adder payments for a resource that was on a planned outage when it telemetered incorrect information to ERCOT.
During the storm, Tenaska Power also telemetered high sustainable limits (HSLs) that incorrectly represented the maximum sustainable energy production capability of resources it represented. The company offered to refund the HSL-related revenues using ERCOT’s alternative dispute resolution process. However, at the time, the process was not an available method to return the excess revenues to the market.
Staff said Tenaska Power has since taken corrective measures to prevent similar issues in the future.
Tenaska Power, a subsidiary of Nebraska-based Tenaska, agreed to the administrative fee and the disgorgement.
Tejas Power Eligible for TEF Bonus
The commission sided with staff’s recommendation to affirm Tejas Power Generation’s eligibility for the Texas Energy Fund’s Completion Bonus Grant program. The generator seeks $17.52 million in performance-dependent grants over a 10-year period for a 146-MW project.
Staff said Tejas Power’s application was administratively complete and that it completed a review process. The grant is contingent on the resource’s timely interconnection to the grid and meeting annual performance measures, including availability for ERCOT dispatch.
Tejas Power is the second recipient of the bonus grant program. The PUC in April entered into a grant agreement with the Lower Colorado River Authority, which is seeking $22.5 million in loans to help build the first of two 188-MW gas-fired units at its Timmerman Power Plant. (See “4 Projects Added to TEF,” Texas PUC Approves 765-kV Transmission Option for Permian Basin.)
LCRA says the unit is scheduled to reach commercial operations in 2025, ahead of its June 1, 2026, deadline to interconnect.
SWEPCO Resiliency Plan OK’d
The PUC approved Southwestern Electric Power’s system reliability plan, but not before reducing the proposed vegetation-management spend by $5.1 million to $83.7 million (57259).
Commissioner Courtney Hjaltman suggested the reduction to reflect what she said were “excessive estimates” for the project costs. The commissioners agreed to remove 26 projects with benefit/cost ratios of less than 1.0, considered the industry standard.
SWEPCO filed the plan consisting of about $183 million of resiliency projects in November 2024. It reached a unanimous agreement with commission staff, the Office of the Public Utility Counsel, Cities Advocating Reasonable Deregulation, Texas Industrial Energy Consumers and Walmart in March.
The PUC also agreed to intervene in support of MISO’s revised expedited resource addition study before FERC that allows a study of a limited set of interconnection requests on an accelerated timeline. FERC rejected the RTO’s first attempt in May, saying the grid operator failed to limit the number of projects that could apply (ER25-2454). (See MISO Reapplies for Generator Interconnection Fast Lane with FERC.)
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.
