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April 29, 2025

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PJM MRC/MC Briefs: April 23, 2025

Markets and Reliability Committee

Stakeholders Endorse Changes to Black Start Compensation

The PJM Markets and Reliability Committee on April 23 endorsed a proposal to rework how resources are compensated for providing black start service the RTO says will provide more predictable revenues for participating market sellers. 

The change was passed with 80% sector-weighted support at the MRC and was endorsed by the Members Committee as part of its consent agenda.  

The package of changes replaces the zonal net cost of new entry in the base formula rate (BFR) equation — used to determine compensation for most black start resources — with a five-year average of the RTO-wide net CONE. The averaged value will be used for the 2025/26 delivery year and adjusted according to the Handy-Whitman index every year thereafter, with the results to be posted by March 31.  

PJM’s Glen Boyle said the RTO’s goal was not to increase or decrease compensation relative to past years but to keep revenues static to avoid having resources exit the market. When PJM seeks additional black start capability through requests for proposals, he said the new resources tend to require upgrades to make them capable of providing the service, which results in them being compensated through the capital recovery factor (CRF). That carries potential for significantly higher costs than maintaining resources being compensated through the BFR. 

During the first read of the proposal in March, Boyle said 29 resources have stopped providing black start service since 2019, 26 of which were replaced through RFPs. All but two of the new resources required upgrades and were initially compensated through the CRF. (See “PJM Presents 1st Read of Proposal to Rework Black Start Compensation,” PJM MRC/MC Briefs: March 19, 2025.) 

Independent Market Monitor Joe Bowring said PJM should carefully consider whether black start resources are being fairly compensated rather than seek what he called an arbitrary change to the formula. In past meetings, he noted that PJM first broached the subject after it determined the scheduled shift to a combined cycle reference resource would cause the net CONE to fall significantly. PJM has since received FERC approval to continue using a combustion turbine as the reference resource. (See FERC OKs Changes to PJM Capacity Market to Cushion Consumer Impacts.) 

The primary purpose of the reference resource is to select the model resource on which capacity market parameters are based — a structure Boyle said PJM does not believe has any relevance to black start compensation. He said the proposal will break the connection between net CONE and black start. 

Greg Poulos, executive director of the Consumer Advocates of the PJM States, said he agrees with the aims of seeking additional transparency and consistency in black start rates, but many advocates are concerned that disentangling net CONE and black start by using the five-year average does not advance those goals. 

“Is there a better way to do this? Make sure it’s fair, and develop a basis to make it fair,” he said. 

PJM Presents Proposal to Add Transparency to ELCC

PJM presented a proposal aiming to provide additional transparency in how it determines effective load-carrying capability (ELCC) class ratings and how those values translate in resource accreditation in the capacity market.  

The package received unanimous support from the ELCC Senior Task Force in a March poll. 

It would require PJM to publish an annual report detailing the class ratings development process, the assumptions guiding the process and an explanation of the results. It would also include an analysis of sensitivities PJM deems relevant. A nonbinding schedule would also be developed to show how the accreditation inputs for each auction are used, including dates for releasing class average and unit-specific performance adjustments. 

PJM would also hold stakeholder meetings prior to developing the study to review the assumptions it is considering using and discuss how changes in the data driving ELCC may affect the outcomes. Similar sessions would be held after the publication to review the results. 

The package would also require PJM to share unit-specific performance data going back to June 2012 with respective generation owners through its Generator Availability Data System. 

The proposal would revise Manual 18 Capacity Market, Manual 20A: Resource Adequacy Analysis and Manual 33: Administrative Services for the PJM Interconnection Operating Agreement. An endorsement vote is planned for the MRC’s meeting May 21. 

Transparency is one of several charges the ELCCSTF was given when it was formed in late 2024, along with the inputs and process PJM uses to determine ELCC values and how investments a generation owner makes in their units can lead to increased accreditation. It is also considering how the shift toward winter risk under the expected unserved energy approach to modeling reliability risks in the ELCC paradigm interacts with the focus on summer peak loads when determining zonal capacity emergency transfer limits. 

First Reads on Manual Revisions

PJM’s Ryan Nice presented a first read on revisions to Manual 1: Control Center and Data Exchange Requirements that includes adding new data requests to the Generation Scheduling Service table. 

The revisions would add the Cold Weather Checklist and Generation Periodic data from the Dispatcher Application and Reporting Tool to the table. They would also align the manual with NERC Standards IRO-010 and TOP-003, both of which are effective July 1 and include a recommendation that changes to transmission owners’ backup functionality operating plans be certified with PJM by Dec. 31, rather than within 60 days. 

PJM’s Suzanne Coyne presented a slate of manual revisions to conform to FERC’s approval of the RTO’s rules for determining clearing prices during a market suspension (ER23-1431). (See “First Reads on Manual Revisions,” PJM MIC Briefs: April 2, 2025.) 

The changes to Manuals 6, 11, 28 and 29 would establish three sets of rules for determining prices based on whether a suspension lasts less than six hours, between six and 24 or longer. Shorter suspensions would use the average real-time prices for each hour prior to and following the outage. For moderate-duration events, day-ahead prices would be used if available; otherwise, real-time prices would be used. For suspensions exceeding a day, an aggregate supply curve would be developed. 

If endorsed by the Market Implementation Committee on May 7, the manual language would be voted on by the MRC on May 21. 

Members Committee

Stakeholders Discuss Posting Board Election Tallies

The Members Committee discussed whether it would be appropriate for PJM to publish the threshold by which candidates for the RTO’s Board of Managers were elected or rejected. Currently PJM states only if a candidate was elected, not exactly how the vote went. 

The subject was broached by Carl Johnson, representing the PJM Public Power Coalition, who said there is interest in having more public information about board elections given members’ dissatisfaction with decisions the board made on revisions to the Consolidated Transmission Owners Agreement (CTOA) last year. The MC rejected endorsement of the proposal to shift filing rights over the Regional Transmission Expansion Plan (RTEP) from membership to the board, after which the board opted to file the changes with the commission later that year. FERC ended up rejecting the revisions. (See FERC Rejects PJM and Transmission Owners’ CTOA Proposals.) 

Representing two members of the Other Supplier sector, Bruce Bleiweis, principal of BN Energy Advisor, said transparency is a core pillar of PJM’s responsibilities and having more information about the board vote would support that. 

PJM CEO Manu Asthana said he does not see any reason why the tallies could not be published. The vote is conducted by a third party to ensure the RTO cannot see how individual members voted, and the sector-weighted results are conveyed to staff. Past practice has been that sector-weighted information is not shared with the public or the board. 

Paul Sotkiewicz, president of E-Cubed Policy Associates, said he is concerned that releasing information about how each sector voted could put targets on sectors’ backs when elections may be contentious. 

Exelon Director of RTO Relations Alex Stern said he does not want board members or PJM to ever see members’ votes, but it does make sense to have more transparency around board elections. 

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Feds Charge Man with Wash. Substation Attacks

The U.S. Department of Justice has charged a Washington man with damaging five electric substations and attempting to damage another in the state in 2022, according to an indictment recently unsealed by the U.S. District Court for the Western District of Washington.

A federal grand jury on April 9 indicted Zachary Rosenthal, a former resident of Tacoma, Wash., with five counts of destruction of an energy facility, one count of attempted destruction and one count of conspiring to damage energy facilities, the U.S. Attorney’s Office said in a press release. DOJ said Rosenthal was assisted by “others known and unknown” in the attacks.

Rosenthal had already been charged with three counts of damaging an energy facility in Portland, Ore., in November 2022, along with alleged accomplice Nathaniel Adam Cheney of Centralia, Wash. Both men have pleaded not guilty, and the Oregon case is set to go to trial on Nov. 3, DOJ’s release said. Rosenthal is currently serving a seven-year sentence in Washington for vehicular assault.

The indictment accused Rosenthal and his co-conspirators of damaging the Toledo, Woodland 1, Woodland 2, Puyallup and Tumwater substations, and attempting to damage the Oakville substation. Attackers used a variety of means to damage the facilities, including firearms, smashing equipment and causing short circuits with heavy chains, DOJ said.

Most of the attacks occurred in November 2022; the Toledo substation attack happened on Aug. 5, and the attempt to damage the Oakville substation occurred Dec. 5.

Investigators said the Washington attacks were part of a plan to shut down power to businesses and ATMs in the area to disable alarms and make them easier to rob. Each event, except for the Oakville attack, caused power outages that affected between 1,000 and 6,000 customers, according to DOJ.

Each count of destruction of an energy facility and causing more than $100,000 in damages carries a penalty of up to 20 years in prison and three years’ supervised release. If the damage is between $5,000 and $100,000, the maximum prison time is five years.

The alleged burglary motive is reminiscent of a similar incident that occurred in Washington in December 2022, when two men caused millions of dollars in damages to four electric substations on Christmas Day, leaving more than 15,000 customers without power. (See Feds Charge Two in Wash. Substation Sabotage.)

The defendants in that case, Matthew Greenwood and Jeremy Crahan, admitted in their plea deals that they wanted to cut power to rob ATMs and businesses. Crahan was sentenced to 18 months in prison in December 2023; a month later, Greenwood was sentenced to three years of probation including one year of home confinement.

Although Greenwood and Crahan’s crimes occurred in the same time frame, with similar goals, and even involved one of the same substations as Rosenthal’s alleged attack — the Puyallup facility — DOJ has not indicated that it suspects a connection between the incidents.

No motive has been suggested for the Oregon incidents, but prosecutor Todd Greenberg told local media that investigators have not found any evidence of ties to extremist groups. Law enforcement officials suggested in 2022 that the attacks, and similar events in the Pacific Northwest around the same time, could be related to “racially or ethnically motivated violent extremists” seeking to sow chaos by disrupting critical infrastructure.

While some of the Washington and Oregon cases now appear to have no political motivations, multiple plots to damage the electric grid for racial reasons have been uncovered since then. Around the same time that Rosenthal was allegedly conducting his attacks, neo-Nazi leader Brandon Russell was developing a plot to destroy electric substations in Baltimore in hopes of sparking a civil war. Russell was convicted in February and faces a maximum sentence of 20 years in prison. (See Neo-Nazi Convicted in Baltimore Grid Attack Conspiracy.)

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After Hitting Milestones, Markets+ Participants Advance on Phase 2

DENVER — Markets+ stakeholders will have little opportunity to ease up in coming months despite a wave of favorable developments for the market.

Those include FERC’s recent approval of the Markets+ tariff, funding agreement and a pair of compliance requests, as well as participants agreeing on most of the market protocols.

SPP has officially set Oct. 1, 2027, as the go-live date for Markets+, its centralized, day-ahead offering in the Western Interconnection. Between now and then, much will happen, with Sept. 1, 2025, emerging as a key date. That is the deadline for balancing authorities to join in time to be a part of the market when it goes live.

“It’s going to be really busy between now and October 1 of 2027,” The Energy Authority’s Laura Trolese, chair of the Markets+ Participant Executive Committee, told RTO Insider April 23. “The utilities and [independent power producers] within the BAs that are joining in the first tranche are going to need to get ready, register, figure out who their market participants are going to be and figure out a lot of different things to move forward with implementation. When an BA joins, now all the loads and resources within that BA are required to register and participate.”

Before then, SPP will begin designing and building the market’s systems and kicking off network and commercial modeling, while stakeholders will begin training on the RTO’s systems.

And with MPEC’s endorsement, the Markets+ Change User Forum (MCUF) will hold its first monthly meeting as Phase 2 gets serious. SPP staff said the MCUF, based on similar groups in previous market developments, will serve as an implementation forum for the Markets+ protocols.

“This is kind of exciting, because this is where it starts,” Don Martin, SPP customer relations manager, said. “It is where you get our people and everybody’s people together. This is where your [energy management systems] team will be talking to these folks. This is where your IT folks will be talking or registering assets.”

The forum is holding its first virtual meeting May 6, five days after Phase 2 starts.

MPEC also endorsed a seams strategy and roadmap paper that lays out focus areas in the future development of polices and governing documents related to seams between Markets+ and neighboring markets and entities. It also documents a “desired end state” for market-to-market relationships with neighboring markets.

Stakeholders unanimously approved the recommendation.

The only motion that received a dissenting vote during the two-day meeting was a recommendation governing meeting attendance and the use of proxies from the Markets+ Interim Governance Task Force (MIGTF). Public interest organizations and other entities with small staffs pushed back against the recommendation that representatives on a working group or task force who miss three straight meetings or appoint a proxy for six straight meetings can be removed from the group by its chair. The MPEC and the Markets+ State Committee (MSC) would be excluded from that provision.

“Those groups that are maybe more capacity resource-constrained tend to rely heavily on proxies in order to maintain effective and consistent participation,” said Renewable Northwest’s Kavya Niranjan, who cast the lone “no” vote. “Our concern with this policy is not that we are not in disagreement with the intention. We feel that, because it can be overly prescriptive, that PIOs that are still trying to engage meaningfully might accidentally or unintentionally get caught up in the overly prescriptive nature of this policy.”

The MIGTF has debated the issue since August 2024, much to the consternation of its chair, Puget Sound Energy’s Jessica Zahnow, who said she just wanted to set clear expectations for attendance and participation.

“When our task force formed eight months ago, I got the list of the six items [to set expectations for recommendations] and I saw attendance policy. I thought, ‘Oh, that’s a slam dunk. That one’s going to be easy. Some of these other things are going to take some work, but this one will be easy,’” she recalled. “It hasn’t been easy, but we have learned a lot.”

Snohomish Public Utility District’s Joe Fina complimented the task force on its effort and their work developing a stakeholder-driven approval process unlike those of other grid operators.

“I was very impressed with the interactions of the task force, the good faith that I think everyone was working under in trying to resolve the concerns that were issued,” he said. “I’m so glad to see kind of the end product here, after being aware of all of the process. I’m not aware in any of the other markets where they go down as deep into the working groups, and they have a similar thoughtful process, proxies and ability. I think that other markets will be looking at this as kind of the model as to how they deal with the similar issue and the work level.”

GHG, Other Protocols Endorsed

In a series of unanimous votes, MPEC approved more than a dozen-and-a-half chunks of the tariff’s remaining protocol language.

That included sections brought forward by the Markets+ Greenhouse Gas Task Force (MGHGTF), which is dealing with one of the more complex protocol sections. The task force began working on GHG pricing protocols in November 2024 after it completed GHG tracking and reporting protocols and developed an appendix providing guidance on creating and submitting mitigated energy offer calculations.

The MGHGTF plans to draft its final pieces of protocol language — focusing on unspecified-source imports and import interchange transactions — in the months ahead, while also ensuring that the market’s implementation is consistent with state regulations.

“There are several things that we are continuing to tackle,” said the Public Generating Pool’s Mary Wiencke, who chairs the group. “I would not want this to be reflected as the GHG Task Force being behind. The GHG Task Force has been working very hard and diligently, but this is a new and novel design, so there are a lot of complex elements to figure out. We still do have some outstanding plan items and action items that we are continuing to work through it.”

She said the Washington State Department of Ecology has an open rulemaking on electricity markets, which has tightened the focus on the group’s work.

“Folks in Washington are very engaged in that process to make sure that what is being developed by the task force is consistent … in terms of the market design reflecting the state regulation and the state regulation reflecting the market design as well,” she said.

The MPEC agreed to reappoint all stakeholder group chairs and vice chairs through its Aug. 12 meeting in Portland. Trolese noted all stakeholder representatives were appointed to two-year terms in April 2023; this will allow a smoother transition when Phase 2 begins with the August meeting, she said.

The MPEC also endorsed three new members for the working groups:

    • Damon Skondin (Tucson Electric Power) for the vacant investor-owned utility seat on the Markets+ Transmission Working Group.
    • Richard Doying (Grid Strategies) and Caitlin Liotiris (Western Power Trading Forum) for the vacant independent seats on the Markets+ Seams Working Group.

Blank on Budget, PSCo Filing

The MSC, comprised of regulators from 13 states, is asking for a $428,680 budget for 2025 to fund one full-time equivalent staffer at the Western Interstate Energy Board this year and retain the MSC’s consultants. The MSC said that will enable the regulators to continue engaging in the market’s development.

Eric Blank, chair of the Colorado Public Utilities Commission and previous chair of the MSC, told the MPEC the budget will be submitted to the Interim Markets+ Independent Panel for its approval.

Blank also said the PUC has a pending application from Xcel Energy’s Public Service Co. of Colorado seeking cost recovery and other approvals to enter Markets+. PSCo filed its request in February. (See PSCo Seeks to Join SPP’s Markets+.)

“Although I can’t say much about pending litigation, I can say that the Colorado PUC is committed to getting a timely decision made to provide greater certainty to SPP and the Markets+ participants,” he said.

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MISO Summer Capacity Prices Shoot to $666.50 in 2025/26 Auction

MISO’s 2025/26 capacity auction returned $666.50/MW-day prices across all zones in the summer, reinforcing the need for members to build new generation fast, the grid operator said. 

While none of MISO’s resource zones experienced a capacity deficit, MISO said it’s inching closer to pervasive shortfalls. The summer’s capacity prices represent a 22-fold increase over summer capacity prices in 2024.  

Beyond summer, MISO zones cleared uniformly at $69.88/MW-day in spring and $33.20/MW-day in winter. For fall, MISO Midwest cleared at $91.60 while MISO South cleared at $74.09/MW-day. MISO said the split in fall pricing occurred due to its transfer limits between its Midwest and South regions.  

Annualized, MISO’s capacity prices are $217/MW-day for MISO Midwest and $212/MW-day for MISO South.  

Prices go into effect June 1, when the planning year begins.  

In the 2024/25 capacity auction, Missouri’s Zone 5 cleared at the $719.81/MW-day cost of new entry for generation in spring and fall. All other zones cleared at $30/MW-day in the summer, $15/MW-day in the fall, $0.75/MW-day in the winter and $34.10/MW-day in the spring. (See Missouri Zone Comes up Short in MISO’s 2nd Seasonal Capacity Auction, Prices Surpass $700/MW-day.) 

The 2025/26 auction was MISO’s first to feature sloped demand curves by season. The grid operator hoped the curves would function as a safety net to have more capacity on hand than strictly necessary to meet planning reserve margin requirements. FERC in 2024 allowed it to use them in place of the vertical demand curve it had been using since 2011. (See FERC Approves Sloped Demand Curve in MISO Capacity Market.) 

MISO said the sloped curves placed an expected higher price on capacity, “reflecting the increased value of accredited capacity beyond the seasonal planning reserve margin target.” The grid operator said the auction cleared 1.9% above its 7.9% summer planning reserve margin, the highest margin it has. MISO said, effectively, it’s heading into summer with a 10.1% summer margin at 101.8 GW in MISO Midwest and an 8.7% margin at 35.7 GW in MISO South.  

Ahead of the auction, MISO anticipated a 122.66-GW summer coincident peak and required a 7.9% planning reserve margin at 135.3 GW for the auction.  

MISO said as with previous auctions, most of its load-serving entities “self-supplied or secured capacity in advance” and thus are shielded from this year’s pricing.  

The RTO said while its sloped curves cleared extra capacity, it noticed the footprint’s spare capacity beyond planning reserve margins dwindled 43% this year compared to summer 2024. MISO said the drop occurred despite a slightly lower planning reserve margin aim than summer 2024’s 9% target. The RTO said it oversaw 140.7 GW in summer 2024 offers and 137.8 GW in summer 2025 offers.  

The 5.1 GW in new capacity, made up mostly of solar generation, and 1.2 GW in capacity accreditation increases added over the last planning year were no match for 4.9 GW in accreditation decreases, 3.3 GW in retirements and suspensions, and a nearly 1-GW loss in external suppliers, MISO reported.   

“New capacity additions did not keep pace with reduced accreditation, suspensions/retirements and slightly reduced imports. The results reinforce the need to increase capacity, as demand is expected to grow with new large load additions,” MISO said in a presentation accompanying auction results.  

Over 2024, MISO and the Organization of MISO States through their joint resource adequacy survey showed that anywhere from a 1.1-GW surplus to a 2.7-GW shortfall could be possible by summer 2025. RTO leadership has been cautioning its stakeholders for more than a year that faster generation additions are a must.  

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Plan Lays out Steps for State-led Interregional Transmission in Northeast

The Northeast States Collaborative on Interregional Transmission released a strategic action plan April 28 for creating an interstate planning process for transmission projects that span the seams of their grid operators.

The collaborative comprises nine states — Connecticut, Delaware, Maine, Maryland, Massachusetts, New Jersey, New York, Rhode Island and Vermont — and was formed with the goal of exploring “opportunities for increased interconnectivity” between ISO-NE, NYISO and PJM. (See 10 Northeastern States Sign MOU on Interregional Transmission Planning.) (New Hampshire signed the initial memorandum of understanding creating the group but did not sign onto the plan.)

The plan, prepared by The Brattle Group, goes further than exploration and into concrete steps for soliciting projects and proposing them to the grid operators. It implicitly criticizes FERC’s planning rules, including the recent Order 1920, for creating barriers to interregional projects.

“No process currently exists for groups of states spanning different transmission planning regions to take the various steps necessary to identify, evaluate, select and agree to share the cost of beneficial interregional transmission projects so they can be developed,” the plan says. “Members of the collaborative have referred to the absence of such a process as ‘the missing middle.’”

Brattle focused on what states can do in the short term — including over the next year — to identify beneficial interregional projects and “make them actionable through existing regional planning processes.” Such projects would help states reach not just their long-term emission-reduction goals but also address their looming resource adequacy concerns.

“New York is pleased to be a part of this strategic partnership so that together with our fellow Northeast states, we can find more effective and affordable solutions to maximizing transmission opportunities that can both provide increased reliability as well as deliver additional clean energy to our grid,” New York State Energy Research and Development Authority President Doreen Harris said in a statement.

Over the next year, the states will attempt to identify “low-hanging fruit” projects through a request for information. Brattle recommends the states ask the three grid operators to take on advisory roles in the process, as any project will need to be integrated into each of their transmission plans. It also suggests including NERC, “given its recent identification of interregional transmission solutions as necessary to ensure a reliable electric grid.” (See NERC Responds to Interregional Transfer Capability Study Comments.)

Simultaneously, Brattle says, the states should consult with the grid operators and FERC on what, if any, tariff changes would be necessary to facilitate the interstate process.

The plan also includes goals for the end of 2027, including the development of HVDC design standards to facilitate an offshore transmission network and joint offshore wind procurements.

“Not having to build new power plants saves Marylanders money,” Maryland Energy Administration Director Paul Pinsky said. “Increased regional transmission capacity can reduce the need for power plants that solely exist to meet peak demand, which are typically fossil fueled. … This collaboration illustrates why state-led climate action is so important to achieving our energy, environmental and economic goals.”

“States across the Northeast share a common priority to ensure an affordable, reliable and sustainable electric grid,” Vermont Department of Public Service Commissioner Kerrick Johnson said. “Transmission is at the heart of securing that energy future.”

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FAQs: Ontario’s Shift to a Nodal Market

To modernize and deliver more efficient markets and ensure customers have reliable electricity at the lowest cost, IESO’s Market Renewal Program (MRP) will transform Ontario’s energy markets by shifting to a nodal market with a formal day-ahead market as well as a virtual market for the first time.  

The market design changes summarized below will introduce more transparency into the price formation through the reporting of nodal LMPs that account for the congestion costs, instead of reporting a system-wide price and handling congestion costs through out-of-market payments. The MRP also will introduce more competition and certainty for market participants through the introduction of a formal day-ahead market as well as a new virtuals market.  

Read on for some frequently asked questions on the key changes happening in IESO in May with the introduction of the Market Renewal Program. IESO is: 

    • Shifting to a single schedule market, establishing one schedule for both pricing and dispatch.  
    • Shifting from a voluntary day-ahead clearing process to a formal day-ahead market (DAM) that is financially binding.  
    • Moving away from out-of-market congestion payments to locational cost of congestion handled in nodal LMPs. 
    • Adopting nodal pricing for all generation resources and dispatchable load customers in the real-time and day-ahead markets, replacing the single price system. There will be about 970 generator and load nodes when the MRP goes live. 
    • Introducing price-responsive loads, a new participation type for load customers. The pricing for non-dispatchable loads will remain uniform across Ontario but will better reflect the congestion costs of delivering energy across the grid. 
    • Introducing a new zonal-based virtuals market that will be financially binding. 
    • Creating the framework to support financial transmission rights (FTRs). While this feature won’t be available at the May 1 launch, the introduction of nodal LMPs and location-based congestion prices sets the stage for future FTR support. 
    • Providing 35 new public reports.  

Key Dates

This section includes key dates and go-live details for the Market Renewal Program. 

When does the IESO MRP go live? 

    • On the morning of April 30, IESO will announce whether the MRP will launch on May 1. 
    • Real-time and pre-dispatch data will be published. 
    • Pre-dispatch data will be published at about 2:36 a.m. EST. 
    • On the morning of May 1, IESO will announce whether the day-ahead market will operate on May 2 for the market day May 3.
    • On May 2, day-ahead market data will be published. 
    • On May 7, price responsive loads (PRLs) will come into effect (registered loads can begin participating as PRLs). 
    • On May 8, virtual trading begins. 

Market Participation Information

This section includes information on market participation requirements.  

Do you have information on minimum market participation requirements, e.g. cash/collateral requirements?  

For this information, see the Guide on Prudentials. A prudential support obligation will be determined separately for physical transactions and virtual transactions, informed by all activity in the day-ahead and real-time time frames. A market participant authorized for both types of transactions will have two separate prudential support obligations. 

Data Publication Information

This section includes information on data publication nuances (e.g., time zones) and data accessibility in the IESO sandbox/test environment. 

How can I access data in the IESO sandbox environment to familiarize myself with the data before market go-live? 

Public site: https://reports-public-sandbox.ieso.ca/public/ 

Gateway sandbox: https://gateway-sbx.ieso.ca/  

How to access the data: https://www.ieso.ca/-/media/Files/IESO/Document-Library/market-renewal/Market-Participant-Testing/Connectivity-Testing-IESO-Gateway.pdf 

Will IESO keep publishing data in EST and not EDT when the clock moves forward? 

IESO will keep publishing data in EST, but the DAM process timelines will follow Eastern Prevailing Time (EPT). 

Pricing Data

This section includes information related to the reporting format of LMPs, reference nodes and maximum/minimum price limits in the real-time market.  

Will IESO publish nodal day-ahead prices ahead of the nodes going live? 

Nodal day-ahead prices are available in the IESO sandbox environment before go-live. Yes Energy already has this data flowing into its products. Note: This is just test data that is meant for market participants to familiarize themselves before the MRP go-live.  

Timing of newly created or updated data IESO reports: 

    • May 1 is the first day of real-time market operation and the first day of real-time report publication. 
    • On May 2, market participants will submit day-ahead market dispatch data. The first day of day-ahead report publication for the trade date is May 3. 

Will the pricing data be reported by locational marginal price components (LMP, congestion, loss) for both nodal and zonal prices? 

The day-ahead and real-time LMP price reports will include the LMP, loss and congestion components for the more than 900 generator and load nodes. The zonal price reports also include the LMP, loss and congestion components. See more information. 

How is the Hourly Ontario Energy Price (HOEP) going to be calculated after MRP? 

After the MRP implementation, HOEP will be replaced by LMPs, and contracts will be settled based on those LMP prices. HOEP’s global adjustment (GA) charge will continue to exist following the implementation for Ontario. 

What’s now the reference node in IESO? 

By default, the reference bus will be the Richview Transformer Station. If the reference bus is out of service, then an alternate station will be chosen as per the prevailing system conditions. 

Is there a maximum or a minimum price in real time in Ontario post-MRP? 

The settlement floor price is -$100/MWh. The maximum settlement will remain at $2,000/MWh. Resources still can offer as low as -$2,000/MWh, however. 

Two-settlement example | IESO

Transmission Congestion Data

This section provides information regarding the availability of transmission constraint data, whether FTRs will be tradable in IESO post-MRP and transmission rights (TR) products. 

Will IESO post binding constraint data? 

Yes, after MRP, IESO will publish real-time, day-ahead and predispatch binding constraint files. Unfortunately, the data will be published on a six-day lag on its public site. Read more about the day-ahead binding constraint shadow price report, the real-time binding constraint shadow price file and the predispatch binding constraint file. IESO will publish day-ahead and predispatch security constraint files on a more real-time cadence, but this provides visibility into the constraints assumed in the day-ahead clearing engine and predispatch engine. Read more about the day-ahead security constraint report and predispatch security constraint report. 

Will shift factors be posted?  

Not directly. IESO used to publish an annual loss penalty factor report. Per IESO, “Loss penalty factors are used to account for the incremental change in transmission losses as a result of the change in output from a resource — including generators, loads and intertie connections.” While they sound similar to a shift factor, the range of 2024 loss penalty factors is 0.91-1.22. IESO says the dynamic loss penalty factors, which will be calculated in each pricing pass of the calculation engine, can be determined using the LMP reports (IESO Publishing and Reporting Market Information (Final), p. 37). 

Will there be an FTR product? 

No, there will not be a financial transmission rights (FTR) product. IESO offers and will continue to offer a transmission rights product that market participants can use to hedge risk (e.g., for unpredictable congestion costs). Transmission rights are traded at the zonal level, not the nodal level. 

Will financial transmission rights still settle on the real-time price, or will they settle on the day-ahead price? 

Under MRP, financial transmission rights will be settled based on the day-ahead congestion prices instead of the real-time price. 

Virtuals Market

This section provides more information on the new virtuals market in IESO, including the number of tradable nodes, price formation and data availability. 

How many zones will be tradable in the virtual market?  

Ontario has 10 electrical zones, but only nine virtual trading zones. The Bruce and Southwest are combined into one Southwest virtual trading zone. See IESO’s Introduction to Virtual Traders Report for more information. 

How is the virtual zonal price calculated? 

Virtual transactions will be settled with the virtual zone prices, which is calculated as the load-weighted average of the LMPs at all load points within the zone. Load distribution factors (LDFs) will be used to determine the weight of each LMP in the virtual trading zone. Like with other prices, day-ahead market and real-time virtual zonal prices will be calculated and used for settlement. Pre-dispatch zonal prices will be provided for information purposes only. 

How far back will the virtual price data be available? 

IESO is launching a virtual market for the first time on May 8. Test data for the new virtuals market is available in the IESO sandbox site.  

Launch plan overview | IESO

Will there be uplifts on virtuals similar to other ISOs in the U.S.? Will there be monthly or weekly settlements for virtuals? 

There will be uplifts on virtuals. Due to the DAM reliability scheduling uplift, virtual transactions can be allocated a portion of the cost of DAM-MWP and DAM-GOG generated in Pass 2: reliability scheduling and commitment of the DAM calculation engine for every MW cleared in the DAM. 

Virtuals will be settled hourly and invoiced monthly. IESO will continue using monthly billing periods for settlement of the physical market (this includes both physical and virtual transactions), so virtual transactions will appear on the monthly invoice. Invoices will be issued 10 business days after the end of the billing period. The market participant payment date is the second business day following the issuance of the invoice. The weekly invoice will continue to contain only settlement amounts for the transmission rights auction. 

Emily Merchant is a director of product at Yes Energy in charge of setting the vision and strategy for Yes Energy’s PowerSignals, QuickSignals and Trading Regions (public data) products. Emily has over 14 years of experience working in the energy industry. Prior to Yes Energy, Emily worked at Navigant Consulting (now Guidehouse), E Source, Energy Trust of Oregon and GDS Associates. 

RTO Insider is a wholly owned subsidiary of Yes Energy. 

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Oxbow Incident: FERC Denies Solar Farm’s Waiver

FERC has denied Oxbow Solar’s waiver request for a 24-month extension of its commercial operation deadline for a planned generating facility in Southwestern Electric Power Co.’s northwestern Louisiana service territory.

In its April 23 order (ER25-1274), the commission said Oxbow Solar had failed to meet FERC’s criteria for waivers of tariff provisions: that the applicant acted in good faith; the waiver is of limited scope; it addresses a concrete problem; and the waiver does not harm third parties or have any other “undesirable consequences.”

FERC found Oxbow Solar failed to show it acted in good faith to diligently advance the solar facility and said it appears “Oxbow Solar’s need for the instant waiver may have been caused, in part, by its own inaction.” The developers did not dispute they failed to meet an amended generator interconnection agreement’s milestone to notify SWEPCO to begin construction or that they met the milestone almost two and a half years late, the commission said.

The planned 73.5-MW generating facility had an initial operating date of Dec. 1, 2023.

FERC also said Oxbow Solar failed to demonstrate that granting the requested waiver would have addressed a concrete problem. It said Oxbow Solar’s only justification is that “the market has corrected for increased project costs.”

“Given the absence of a detailed explanation in the record of how the 24-month extension will allow Oxbow Solar to secure financing and achieve commercial operation, we find that Oxbow Solar has failed to sufficiently demonstrate that its waiver request will remedy a concrete problem,” the commission wrote.

Oxbow Solar had requested the extension, from Nov. 30, 2026, to Nov. 30, 2028, back in February. It said rapid increases in insurance, engineering, procurement, and construction costs and difficulties in securing solar components had hampered its ability to negotiate offtake agreements in time to meet the commercial operation deadline.

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What to Know About IESO

RTO Insider is beginning regular coverage of Ontario’s Independent Electricity System Operator (IESO) in conjunction with the region’s transition to a nodal market May 1. (See related story, Ontario Introducing Nodal Market May 1.) 

Here’s an introduction: 

How does it compare with organized markets in the U.S.?

IESO has 37.2 GW of installed capacity and 18,640 miles of transmission, both ranked seventh among the nine organized markets in the U.S. and Canada. It hit its peak demand, 27,005 MW, in August 2006. Its record winter peak, 24,979 MW, was set in December 2004. 

How is power demand expected to change in the future?

The 2025 Annual Planning Outlook demand forecast forecasts a 75% increase in electric demand by 2050 — up from the 60% increase forecast a year earlier — driven by industrial and data center growth in addition to commercial sector growth, increasing population and electrification. Annual consumption is seen rising from 151 TWh in 2025 to 263 TWh in 2050. 

Annual energy demand | IESO

Who owns and controls IESO?

IESO is a “Crown corporation,” a government organization with a mixture of commercial and public-policy goals, owned by the government of Ontario. 

It is governed by a board whose directors are appointed by the provincial government. 

Before 1998, Ontario Hydro and municipal utilities provided power to Ontario, with electricity prices set by the provincial government. 

The Ontario Electricity Act of 1998 split Ontario Hydro into IESO’s predecessor and four other companies, including:  

      • the Electrical Safety Authority (ESA), which regulates and promotes electrical safety;
      • the Ontario Electricity Financial Corp. (OEFC), which is responsible for managing Ontario Hydro’s debt and contracts with non-utility generators;
      • Ontario Power Generation (OPG), which took over Ontario Hydro’s generation and now owns 66 hydropower stations, two nuclear stations and a handful of solar and gas generators in Ontario;
      • and Hydro One, which assumed Ontario Hydro’s transmission and distribution assets and now serves 1.5 million predominantly rural customers. 

IESO, originally called the Independent Electricity Market Operator (IMO), was created to prepare for deregulation of the province’s electrical system. It assumed the grid management functions of Ontario Hydro and was charged with developing a new electricity market. 

The wholesale electricity market opened in May 2002, and the IMO was renamed IESO in January 2005.  

How is IESO regulated?

The Ontario Energy Board regulates electric companies and sets residential electricity rates; it also approves IESO’s budget and fees. The OEB reports to the Ministry of Energy and Mines, which sets overall policies for the electricity sector.  

In an October 2024 report, Minister of Energy and Electrification Stephen Lecce signaled a shift from the previous Liberal government, which Lecce’s Progressive Conservative Party ousted in 2018, criticizing its “failed and ideologically driven energy experiments” and “sweetheart deals that paid several times the going rate for power,” a reference to 33,000 renewable energy contracts signed between 2004 and 2016 at up to 10 times the prevailing power prices. 

Lecce called for “an all-of-the-above approach to energy planning, including nuclear, hydroelectricity, energy storage, natural gas, hydrogen and renewables, and other fuels, rather than ideological dogma that offers false choices and burdens hardworking people and businesses with a costly and unnecessary carbon tax.” 

He touted “the largest expansion of nuclear energy on the continent with the first small modular reactor in the G7. The province is upgrading and refurbishing existing reactors at Darlington, Pickering and Bruce Power to extend their lifespan and building four 300-MW SMRs at Darlington.  

What is its fuel mix?

Nuclear (53%) and hydropower (25%) constitute more than three-quarters of IESO’s fuel mix, up from 66% in 2003. Wind (8%), solar (0.5%) and biofuel (0.4%) have increased their shares from a combined 1% in 2003. Gas and oil represent 13% (up from 11% in 2003). 

Coal, which represented one-quarter of generation in 2003 — and most of the system’s flexibility, according to IESO — was eliminated in 2014. 

Where is it expanding transmission?

IESO is developing five new transmission lines in southwestern Ontario to serve auto manufacturers and agriculture, two new lines in northeastern Ontario to support a steel mill’s planned conversion to electricity and mines, and one line in eastern Ontario to serve the Peterborough and Ottawa regions. 

How does it incorporate stakeholders in new market rules?

IESO says it dedicates one to three days each month for stakeholder engagement meetings. Current engagement issues include local generation, demand side management, the annual planning outlook and capacity auction enhancements. 

Planned transmission projects | IESO

In addition, the Strategic Advisory Committee provides feedback to IESO’s Board of Directors and executive leadership team. Current members represent generators, transmission and distribution companies, communities, consumers, and energy-related businesses and services. The committee held three public meetings in 2024. 

The Technical Panel reviews proposed changes to market rules. Its current members include representatives of generators, renewable generators, energy-related businesses and services, importers and exporters, transmission and distribution companies, market participant consumers, residential consumers and demand response providers. It has scheduled seven meetings through the end of 2025. 

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CPUC, Others Question Details of EDAM Congestion Revenue Proposal

Stakeholders and state energy officials continue to raise concerns about a CAISO draft proposal that would adjust how congestion revenues are allocated in its Extended Day-Ahead Market, with the ISO aiming for a vote on the final proposal in the coming weeks. 

The draft proposal, released last week, addresses how the EDAM will allocate congestion revenues when a transmission constraint in one EDAM balancing authority area causes parallel flows in a neighboring BAA.  

CAISO has said the draft proposal will be ‘transitional’ over the next three years, after which time it plans to implement a more permanent design. 

The proposal is a product of the past two months of focused work on the subject. In March, CAISO launched an expedited initiative to address stakeholder concerns, and this week, the agency held an all-day meeting to review the proposal with the more than 150 participants who joined the call. 

At the April 24 meeting, California Public Utilities Commission regulatory analyst Michele Kito asked if the ISO had a sense of where the major parallel flows currently take place on the system. 

“I would imagine that we can look at historical system data,” Kito said. “Do we have any sense of what those [parallel flows] are and what the effects each of these proposals have in terms of revenue allocation?” 

“We haven’t looked at specific parallel flow impacts,” George Angelidis, CAISO executive principal, said at the meeting. “There are well-known transmission bottlenecks in the ISO system, like Path 36 and Path 15, but in general, any kind of flow in the system will experience what we define as parallel flow.”  

Parallel flow is the impact on the flow gauge of transactions that are external to that BAA, Angelidis said. They can be infinite: Any path will have parallel flows, so CAISO has not looked at potential parallel flow results on specific flow gauges, he said. 

Cathleen Colbert, senior director of Western markets policy at Vistra Energy, added, “I will give a little extra support to Michele’s questions. Do we not have any sense of how these parallel flows work on internal constraints? I do think there’s a case for you guys to provide some additional kind of forward-looking information.” 

CAISO will be studying these parallel flow effects over the three-year period of the new design, said Milos Bosanac, ISO regional markets sector manager. 

“As entities join the EDAM, we will be modeling transmission constraints on their system that may not necessarily be reflective today,” Bosanac said. “I think it’s difficult to surmise the effects at this point in time of constraints that might not yet be modeled. [However], we will be modeling the new design on PacifiCorp’s system, and as other entities join, we will model those effects [too].” 

Middle Approach

Under current EDAM market rules, Open Access Transmission Tariff (OATT) customers in one BAA will end up paying costs for congestion for parallel flows caused by binding transmission constraints in neighboring BAAs. However, under the draft final proposal, parallel flow congestion revenues collected in a BAA that result from a binding constraint in a neighboring area will first be allocated to the BAA in which the overflow congestion occurs and the revenues are collected.  

In an example reviewed at the meeting, $135,800 in congestion revenue was collected and distributed to three balancing areas: BAA A, BAA B and BAA C. Under the current design, all $135,00 would be distributed to BAA A. However, under the draft proposal, BAA A would receive $132,800 in revenue, BAA B would receive $1,000, and BAA C would receive $2,000.  

The final draft proposal supports EDAM entities’ capacity to provide congestion cost protection for transmission customers exercising firm OATT rights, Bosanac said. The draft also addresses stakeholder concerns about a balancing area being exposed to congestion costs when providing counterflow effects in relation to constraints, he said. 

The draft would apply only to the day-ahead market, not to the real-time market. The real-time market retains the congestion revenue allocation in effect today in the WEIM “in order to minimize the impact on the WEIM participants,” Bosanac said. 

If approved, CAISO will implement the draft final proposal by collecting data and monitoring the congestion effects over the first one to two years of the transitional approach. CAISO will then prepare a permanent design after the three-year period. 

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Consumers Defend Local Transmission Planning Complaint from Protests

Consumer groups defended their complaint with FERC alleging utilities were spending too much on lightly regulated local transmission projects against arguments that such spending is justified (EL25-44).

In a joint answer to protests filed April 24, the 22 groups — including the Industrial Energy Consumers of America, American Forest & Paper Association and R Street Institute — argued that the December 2024 complaint against all FERC-jurisdictional transmission planners should be granted so the commission can address what they called widespread unjust and unreasonable planning practices. (See Utilities Ask FERC to Toss Local Tx Planning Complaint, Others Support It.)

While the transmission lines can be called “local,” those at issue in the complaint are located in the Eastern and Western Interconnections and are part of interstate commerce. That has long been recognized by the courts, the groups said.

“Respondents nevertheless insist that planning of interstate transmission at the individual level remains appropriate because such transmission is ‘local’ and that existing transmission owners have a ‘right’ to plan the interconnected grid of the future simply because they built the grid of yesterday,” they said. “Respondents make no electrical distinction between local and regional transmission.”

The actual difference between “local” and “regional” projects can be arbitrary, the groups argued, noting as an example that American Transmission Co. independently started planning a 345-kV line, which was then selected by MISO for its regional transmission plan, with its costs spread across the footprint.

“ATC argues that ‘the project directly contradicts the “piecemeal planning” allegations contained within the complaint,’ but the project actually proves the point of the complaint, as MISO recognized that the project impacted the entire region, although it was initially individually planned,” the consumer groups said. “The electrical nature of the project did not change through the regional review, and the complaint identified hundreds of similar projects that were individually planned with no substantive regional review.”

A common rebuttal to the complaint was that utilities had to retain their planning role to effectively meet state retail obligations, which leaves it outside of FERC jurisdiction.

“The complaint is based on the simple electrical premise that there is no FERC-jurisdictional ‘local’ transmission and thus there are no ‘local’ transmission planning needs,” the groups responded. “There are localized inputs to determining the holistic needs of the interconnected grid, but electrical facilities at 100 kV and above are not local, except those excluded by the complaint.”

Local projects that solely serve intrastate needs are outside of FERC jurisdiction, and the complaint does not ask FERC to try to regulate them.

Many protesters argued that the complaint is too broad, and the commission should take regional differences into account if it decides to grant it.

“Individual or even regional ‘planning challenges’ or differences are irrelevant to the fundamental question under the complaint as to whether it is appropriate to allow individual transmission owners to plan 100-kV and above transmission in interstate commerce based on the ongoing false premise that such transmission planning relates to ‘local transmission,’” the groups answered. “Planning challenges, to the extent they exist, can be incorporated into the required regional planning, just as regional differences are incorporated today in regional planning.” FERC can grant the complaint and facilitate implementation of any necessary region-specific reforms through compliance filings, they argued.

Another common rebuttal was that the complaint had to prove that local planning leads to unjust and unreasonable rates on specific projects, but the groups argued it was aimed at local planning practices and that Section 206 of the Federal Power Act can address broad industry practices.

“Critically, acceptance of respondents’ arguments would also mean that FERC, under a rulemaking pursuant to Section 206, wouldn’t be able to dictate nationwide standards, like in Orders Nos. 890, 1000 [and] 1920,” they said.

Opponents also argued that the complaint was a collateral attack on Order 1920, or even earlier transmission planning rules, but the groups said they had put new evidence in front of FERC that it did not have during the proceedings that led to its most recent transmission planning rule.

“The new evidence and changed circumstances consist of new analytical reports and evidence of both individual projects and cumulative regional transmission plans and portfolios across every planning region over several years,” they said.

Other Parties Defend the Complaint

American Municipal Power also filed an answer April 24, arguing FERC should grant the complaint despite a request from PJM and its transmission owners to dismiss it.

The complaint made the case that spending on local projects in PJM has become unjust and unreasonable and should be dealt with in a subsequent show-cause proceeding, AMP said.

Transmission rates in PJM are up 237% from 2011, mainly from local projects with limited oversight, AMP said.

“Forcing local transmission customers to bear the cost of projects that should have been supplanted by more cost-effective regional projects could unduly discriminate against those local customers by unfairly shifting the cost of transmission projects in a manner inconsistent with cost-causation principles,” AMP said. “The harmful effect of these failures would only multiply going forward, as PJM’s load is expected to grow by 70 GW or more in the foreseeable future.”

The Maine Public Utilities Commission similarly rebutted claims about local planning in New England. It said FERC should open another Section 206 show-cause proceeding so it can address the issues around local planning and its lack of oversight in New England.

Projects above $5 million are presented to ISO-NE’s Planning Advisory Committee, but the process has proven inadequate, and the TOs retain all control over asset-condition projects in the region.

The PUC “completely agrees that the ISO-NE tariff and related documents do not provide ISO-NE with a role in local transmission planning sufficient to effectuate all of the remedies sought by complainants, but [it] submits that a Section 206 investigation will allow parties to build a record upon which remedies consistent with Order No. 890 and FERC precedent may be developed specifically for the New England region,” it said.