Search
December 8, 2025

Posted on

Power Play: Extreme Heat is Set to Test Grid Reliability, Human Resiliency

Dej Knuckey

Summer’s officially over, white shoes have been relegated to the back of the closet, and pumpkin spice everything is back. Now that the worst of the hot weather is most likely behind us for the year, it’s a good time to reflect on the pressure that extreme heat puts on the electric system. 

Extreme weather has earned its way onto the short list of life’s certainties. Whether it’s heat waves, excessive precipitation, storms or freezes, there’s a higher chance than ever that where you live or where your company does business will be affected by extreme weather in ways that are as varied as the biblical plagues.  

Heat affects the full length of the electric supply chain, from generation, through the grid, to utilities’ customers. In the first of a series on the impacts of climate extremes, this column will dig into the many ways hotter weather challenges the electric system. 

Hot Town, Summer in the City

Extreme heat drives demand spikes. On July 28, 2025, peak demand in the lower 48 states broke the record set in July 2024, only to surpass it the next day. The peak demand of 759,180 MW between 6 and 7 p.m. July 29, adjusted for time zones, was nearly 2% higher than the July 2024 record. 

| EIA

The demand is driven largely by an increase in the cooling load, though there probably were some AI servers churning out answers to heat-related questions: How can I cool my home? Will a blended margarita cool me down more than one on the rocks? 

It’s not a surprise that demand spikes with heat: Who doesn’t want to walk into a cool home at the end of a hot commute? But heat waves are changing what these demand spikes look like. It’s not just that it takes more energy to cool a home when outdoor temperatures are higher than usual, but also that those with air conditioning are using it longer.  

Heat waves can show no mercy at night. Earlier in 2025, some areas in the Southwest saw overnight lows as high as 95°F. This means household cooling loads extended well beyond the typical peak hours from 4 p.m. to 8 or 9 p.m.  

Cooling a home becomes more challenging as the heat wave lingers. A home’s thermal mass—dense building materials such as brick, concrete or stone — absorbs heat and radiates it out during cooler periods. Usually, the thermal mass protects a home from heat (that’s why it’s cool inside a building with thick stone walls), but exposure to multiple days of extreme temperatures can slow down how a home cools at night and result in heat continuing to radiate after the heat wave ends.  

Growing home sizes and increasing adoption of home cooling systems also increase demand. The results can be a capacity deficiency as demand spikes in areas not known for extreme heat, such as the spike ISO-NE dealt with in June. 

The biggest change is happening in what the Building America program calls the marine climate region, which extends from the San Francisco Bay Area along the coast all the way to Canada. After record-breaking heat waves in the Pacific Northwest — in June 2021, Portland hit a record 116°F while Seattle hit 108°F, and then in late August 2025, Portland again recorded temperatures over 100°F — installing air conditioning in new homes is becoming common.  

The bottom line: The grid will need to plan for ever-higher and longer demand spikes if it wants to maintain reliability. 

Heat Strains Supply on Many Fronts

If the only challenge were meeting those demand spikes, the electric system probably would be in good shape. But generation and the grid itself are less efficient during extreme heat, sometimes dramatically so. 

The first challenge comes from hot air being less dense: Combined cycle and gas combustion plants are less efficient when the air mixed with the gas to combust in the turbines is less dense.  

Efficiency losses vary based on technology, but almost all are affected by heat, according to the Union of Concerned Scientists: “Many types of power plants become less efficient at higher temperatures. A gas turbine rated at 60° F might be able to generate only 85% of that capacity when ambient temperatures reach 100° F, for example.” 

Similarly, power plants that use dry cooling, which works like a giant car radiator, have difficulty when the air needed for cooling already is heated. 

The bigger challenge comes from hot water: All generation plants that involve combustion require cooling, regardless of whether they burn fossil fuels or split atoms. Most use water for cooling, which means drawing from seas and the like. If that water is hotter than usual before the cooling process, it will be less efficient at cooling, and there usually are limits on discharging hot water. 

For example, nuclear reactors in Switzerland and France were throttled after heat waves warmed the water coming in so much that it couldn’t effectively cool the plants and environmental restrictions prevented them from discharging hot water into already overly warm rivers. 

While most of these losses can be anticipated, extreme heat can cause extreme outcomes. 

Attack of the Overheated Jellyfish

Not once, but twice this summer, the European grid had to cope with unplanned supply shocks because of [checks notes] jellyfish…?  

It’s a story that sounds straight out of the eco-thriller “The Swarm”: The warming planet leads to a hotter English Channel, causing jellyfish to thrive, resulting in a “massive and unpredictable” horde of them in a French nuclear plant’s seawater cooling system. It happened in August, and closed four of six reactors, cutting output by 3.6 GW. Less than a month later, and only 165 miles up the road, another jellyfish swarm led to the shutdown of one reactor and the throttling of another, taking 2.4 GW offline.  

While jellyfish swarms may be unpredictable, what we can predict is that heat waves will have widespread and varied consequences. 

Renewables also are Challenged by Heat

Certain types of heat can make wind farms less efficient too. Heat lowers air density, and wind turbines produce less power when the air’s easier for the blades to pass through, so any hot day will cut production. However, when a stagnant high-pressure weather pattern settles in and creates a heat dome, the problems multiply: Low winds and less variation in wind speeds at different heights from the ground both cut output. A research paper in Europe found the impact varies by location, but one heat wave cut wind power output by more than 30%. 

Hydroelectric output’s not immune either. Early heat waves in 2023 melted snowpack in the Pacific Northwest, leaving less water flow for the summer. Overall, the May heat wave decreased output 23% in Washington state across the 2022/23 water year. (Like the school year, the water year is not aligned with the calendar: It starts on Oct. 1.) Of course, heat often is associated with drought, which also limits hydroelectric output. 

What about solar? More sun is good, right? Not if it comes with heat. There’s a reason Chile’s Atacama Desert is a prime location for utility-scale solar: It’s cool and sunny. Electronics are more efficient as temperatures drop, and every degree of extra heat lowers the output of a solar module. 

Solar module datasheets include a measure called Pmax: the peak power the module can produce at standard operating conditions of 25°C (77°F). Right after that number, there’s always a temperature coefficient: the percentage drop in efficiency for every degree Celsius above 25°C. 

While newer solar modules are less temperature sensitive, most still lose around 0.35 to 0.40% efficiency for each degree. This means that back in May, when Texas hit an early heat wave, exceeding 100°F (38C) in Austin — more than 7°C above the average high of 87°F (30.5°C) — the solar farms were delivering at least 2.6% less peak power than they would have on a normal summer day.  

That sounds like a small amount of loss, but it was significant, as ERCOT recorded peak usage of over 78 GW, setting a record in May and again pushing the grid to its limits in July. And who wants their utility asking them to limit the use of air conditioning when the nights get down only to the 80s? 

Even the Grid Wilts in the Heat

Like all of us, the grid is saggy and inefficient during heat waves. The power lines not only stretch, but also are less efficient conductors as the heat vibrates the conductive material and slows the flow of electrons. So, line losses, which typically consume 5% of electricity across the grid, increase during heat waves, meaning more generation is required to deliver the same amount of electricity where it’s needed. 

PNNL researchers have discovered that adding graphene to copper conductors reduces heat-related disruptions. However, with 5.5 million of miles of transmission and distribution lines already deployed, it’s unlikely that efficiency will improve anytime soon.  

Labor Sizzles as Temperatures Soar

As heat waves get longer and hotter, generation asset construction and grid upgrades and maintenance also are at risk. Heat accounts for about $100 billion in lost productivity nationally, and any industry where labor works outside is affected. 

Some states are instituting worker protections that require breaks, shade and other cooling for outdoor workers (as someone who’s at high risk of heat stroke, I have to give a shout-out to Heat Relief Depot’s phase-changing vests). Some of those regulations have followed heat-related deaths. Other states, such as Florida, are doing the opposite: banning worker protections. But with or without protection, it’s reasonable to assume outdoor worker productivity will decline during excessive heat. 

Upstream is not Immune

While we’ve looked from generation to end user, extreme heat has effects all the way upstream in the fossil industry.  

In the ultimate irony, melting permafrost puts pipeline foundations at risk of sinking and causing a rupture in the pipeline. It’s a problem in Alaska and other arctic regions, and often is managed using passive thermosyphons (think of vertical radiators around pilings). However, hotter ambient air renders them less effective, and refreezing the permafrost under pipeline footings may require running fossil fuel-powered chillers.  

A Hot Take on the Markets

The industry already knows how to manage hot weather. However, to think of extreme heat events as just extra hot weather is a mistake. Excessive and persistent heat, with little nighttime relief, creates challenges that are more diverse and harder to model. So, how should the electricity markets plan for extreme heat?  

First, it means that the RTOs are on the right path as they aim to raise installed reserve margins and encourage demand response programs. And utilities should incentivize anything that can temper those peaks, from distributed energy storage to more efficient cooling technologies, such as rebates for mini-splits. 

Second, as extreme heat events become more common, the industry needs to plan for them in a nuanced way. It’s critical to understand the wide and varied impact on generation assets. Gas and nuclear? Keep an eye on how they keep cool. Wind? Beware of the heat domes. And given that solar’s decline in efficiency in extreme heat events is easy to calculate (and has zero jellyfish-related risk), it may be time for RTOs to reconsider how they think of solar’s reliability. It’s not just about generation assets: The industry’s ultimate asset is its people, so thinking about worker safety also is critical. 

Finally, extreme heat risk reinforces the need to diversify generation and consider where energy storage assets can best act as a shock absorber for the grid. They are, of course, useful sited next to intermittent generation assets, but there’s a strong argument to think of all generation assets as intermittent when extreme heat events are concerned.  

Power Play Columnist Dej Knuckey is a climate and energy writer with decades of industry experience. 

Posted on

Calif. Lawmakers Pass Bill to Accelerate Transmission Development

The California legislature has passed a bill that would create a “transmission accelerator” to develop low-cost public financing programs for certain transmission projects.

Senate Bill 254, by Sen. Josh Becker (D), would also establish an $18 billion “continuation account” for the state’s wildfire fund to cover investor-owned utilities’ wildfire liabilities. Contributions to the fund would be split between ratepayers and shareholders.

Lawmakers passed the bill Sept. 13 in the final hours of the 2025 legislative session. If signed by Gov. Gavin Newsom, the urgency measure would take effect immediately.

Becker said the bill, which was 361 pages, was the culmination of three processes. Elements of his initial bill were combined with consumer affordability measures developed in the state Assembly, as well as Gov. Gavin Newsom’s proposal to shore up the state’s wildfire fund.

During the Sept. 13 floor session, Senate President Pro Tem Mike McGuire thanked Becker for his perseverance on what he called one of the largest energy reform bills in state history.

“This bill has died about 10 times, and you’ve stuck through it,” McGuire said.

Becker pitched his bill as a way to rein in rising electric bills.

California investor-owned utilities’ electric rates traditionally have been higher than the national average and are rising rapidly, a legislative analyst said in reviewing SB 254. Electric rates charged by Pacific Gas and Electric (PG&E), Southern California Edison (SCE) and San Diego Gas & Electric (SDG&E) have risen by 127, 91 and 72%, respectively, over the last decade, the analyst said.

SB 254 “will save ratepayers billions, stabilize our utilities and make sure the grid can support housing, clean energy and economic growth,” Becker said in a release.

One way the bill aims to save money is through a California Transmission Accelerator within the Governor’s Office of Business and Economic Development. Eligible transmission projects could receive low-cost public financing through the California Infrastructure and Economic Development Bank.

The bill gives the accelerator a Dec. 31, 2026, deadline to coordinate transmission planning activity in the state “in order to minimize duplicative efforts” and increase efficiency.

The accelerator would review results of CAISO’s transmission planning process and choose projects to be eligible for public financing. Projects must be consistent with the state’s reliability and greenhouse gas policy objectives.

The applicant must have successfully completed a previous California transmission project.

Recipients would repay the loans to an accelerator revolving fund so the money could be used for other transmission projects.

The Transmission Accelerator appears to replace the Clean Energy Infrastructure Authority that was proposed in a previous version of the bill but was subsequently scrapped. (See Calif. Bill Seeks to Control Electric Bills, Create Transmission Authority.)

Wildfire Fund

California launched its wildfire fund in 2019; utilities may tap into it to pay claims for damages resulting from a wildfire caused by utility equipment. PG&E, SCE and SDG&E contribute to the fund, as do electric ratepayers.

Without the proposed continuation account, the state’s wildfire fund could run dry due to claims from the 2025 Eaton fire in Southern California, a legislative analyst said.

Under SB 254, electric customers would pay into the continuation account through an existing charge on their bills, which is set to expire in 2035 but would be extended for 10 years.

Without the wildfire fund, Becker said, “ratepayers are on the hook for everything because of inverse condemnation,” which holds utilities liable for all damage caused by their equipment regardless of a finding of negligence.

If the wildfire fund runs out, SB 254 would allow utilities to use ratepayer financing to cover any settled wildfire claims between Jan. 1, 2025, and the time the bill takes effect.

The passage of SB 254 follows Newsom’s comments in August that he’d be working with lawmakers to boost the wildfire fund by $18 billion. (See Gov. Newsom Proposes Additional $18B for Calif. Wildfire Fund,)

Energization Timelines

Becker said the bill would add “teeth” to existing law regarding timelines for utilities to energize new customers.

Under current law, the California Public Utilities Commission sets reasonable average and maximum energization timelines. Customers may report delays.

SB 254 would require CPUC to draw up an enforcement policy for those timelines, including penalties, by Jan. 1, 2027. CPUC would also consider requiring utilities to have executive compensation incentives based on whether the utility is meeting energization timelines.

CPUC would also require utilities to hire a third-party auditor to review their energization practices.

In other provisions, the bill would block utilities from earning a profit on $6 billion in fire risk mitigation projects starting Jan. 1, 2026. It would also require more transparency into utility profits, so that consumer advocates and others can better gauge whether the profits are just and reasonable.

Posted on

Stakeholders Urge Cyber Info Sharing Act Renewal

A key cybersecurity law is to expire at the end of September, and industry stakeholders say the security of the electric grid could be seriously hampered if lawmakers do not act soon to renew it. 

The Cybersecurity Information Sharing Act of 2015 set requirements for the Departments of Homeland Security, Defense and Justice, along with the Director of National Intelligence, to share information on cybersecurity threats with private entities; state, local and tribal governments; and the general public. It also provides liability protections for entities that voluntarily share and receive cyber threat indicators and defensive measures with other entities or with the government. 

The law has mostly succeeded in these goals, according to government studies. In a 2023 report, staff of the Office of the Inspector General of the Intelligence Community found that all of the departments named in the law had met its information sharing requirements and that the private sector was using the information sharing tools that agencies had put in place since its passage.  

Similarly, authors of an analysis from the Government Accountability Office the same year observed that agencies had identified barriers to information sharing across the government as required by the act and were developing strategies for removing those barriers. 

But cybersecurity professionals in multiple industries have expressed concern that the information sharing environment fostered by the law will decay quickly if the act is allowed to expire Sept. 30. Several electric industry stakeholder organizations joined a letter from the U.S. Chamber of Commerce to Congress in May 2025 urging reauthorization, including the Edison Electric Institute, Electric Power Supply Association, GridWise Alliance, Large Public Power Council and National Electrical Manufacturers Association (NEMA). 

“It’s important to ensure that you know what are the common threats that industry is seeing, what are tactics that bad actors are implementing, what’s the chatter in the dark web around these actions?” Peter Ferrell, director of government relations at NEMA, told ERO Insider. “If those [electrical] systems go down … they don’t easily come back up. And so ensuring that those systems are as secure as possible, and sharing information among industry members [and] government partners is super critical.” 

Ferrell couldn’t share details on the electric industry’s use of the law because of confidentiality concerns but did suggest that “the fact that you haven’t heard about it more is probably proof that it does work.” 

“No one reports things when they don’t happen; they only report things when they do happen. So, while there have been major exploits over the past 10 years, and they are significant, you don’t see a lot of attacks happening on the manufacturing side of things.” 

Members of the government have shared similar sentiments. Testifying before Congress in May 2025, Brandon Wales, former executive director of DHS’s Cybersecurity and Infrastructure Security Agency, called the act “an important tool to facilitate the flow of critical cyber intelligence” and said “letting it expire would be a huge step back.” At the same hearing, former acting National Cyber Director Kemba Walden not only pushed for reauthorization but urged Congress to update the act to clarify authorized defensive measures. 

Efforts are under way to extend the act before it expires. Rep. Andrew Garbarino (R-N.Y.) introduced a bill Sept. 2 that would reauthorize the law through 2035 while updating definitions of “artificial intelligence” and “critical infrastructure,” and requirements on industry outreach. The bill has not yet been assigned to a committee. 

Ferrell acknowledged the introduction of the bill and said NEMA would welcome updates to modernize the act but emphasized that the most important thing for the organization and other stakeholders is to ensure there is no gap in its information sharing protections. 

“There are many pathways that it could possibly go in terms of being reauthorized. But [we hope] that there is no lapse, even a short one,” Ferrell said. “Trust takes a long time … to develop, but it’s very easily eroded. And so we hope that Congress and the powers that be come together and provide a long-term runway. … The sector needs this in order to make sure that [we can hit] those other, bigger policy and economic goals that America is trying to achieve.” 

Posted on

IEA Charts Slower Progress on Low-emissions Hydrogen

The International Energy Agency expects low-emissions hydrogen production to increase substantially through 2030, but not as rapidly as had been expected a few years ago. 

The forecast is contained in “Global Hydrogen Review 2025,” the annual analysis IEA issued Sept. 12. The report also indicates limited progress so far toward a cleaner hydrogen sector: 

Worldwide hydrogen demand reached nearly 100 million tons in 2024, up 2% from 2023; almost all of it was produced from fossil fuels with conventional techniques, and the bulk of it went to sectors that traditionally have been the largest hydrogen consumers, such as industry and oil refining. 

Producing gray hydrogen (and its associated carbon dioxide emissions) from fossil fuels has always been cheaper than producing green hydrogen through emissions-free electrolysis of water, and the cost differential has widened recently due to lower natural gas costs and higher electrolyzer costs, IEA said in its announcement of the report. 

At the same time, uncertainty surrounds demand for low-emissions hydrogen and the regulations upon it, IEA said, and development of the infrastructure needed to support expansion of the hydrogen sector has lagged. 

As a result, the 2025 review tallies potential low-emissions hydrogen production at no more than 37 million tons in 2030, down 24% from the 49 million tons the 2024 review calculated. And IEA reminds readers that the actual 2030 production is likely to be much less than 37 million tons, due to project attrition. 

The projects that are operational or under construction or have reached final investment decision would produce just 4 million tons per year in 2030, IEA said, though other projects that have a “strong potential” of completion if granted a favorable regulatory environment could add 6 million tons to the total. 

On a more positive note, IEA said there were just a handful of low-emissions hydrogen demonstration projects when it published its first review in 2021. As it published its fifth, more than 200 investment commitments have been made. 

IEA Executive Director Fatih Birol said the investor interest in hydrogen that spiked in the early 2020s has cooled but not vanished: “The latest data indicates that the growth of new hydrogen technologies is under pressure due to economic headwinds and policy uncertainty, but we still see strong signs that their development is moving ahead globally. To help growth continue, policy makers should maintain support schemes, use the tools they have to foster demand and expedite the development of necessary infrastructure.” 

With release of the 2025 review, IEA updated its Hydrogen Production and Infrastructure Projects Database and launched a new online tracker that maps or charts projects, production, infrastructure, production costs and policies. 

Among the details in the 2025 review: 

    • Green hydrogen projects accounted for more than 80% of the decrease in expected production levels of low-emissions hydrogen in 2030, but blue hydrogen projects — gray hydrogen production coupled with carbon capture technology — also were removed from the mix. 
    • Low-emissions hydrogen production is expected to increase 10% from 2024 and reach 1 million tons in 2025, which would place it around 1% of all hydrogen production. 
    • The cost gap between green and gray hydrogen is expected to narrow by 2030 in parts of the world, but in places where natural gas is less expensive, such as the United States and the Middle East, the gap will remain wide, making blue hydrogen more attractive than green. 
    • China is a low-emissions hydrogen hot spot: 65% of worldwide electrolyzer capacity has been built or greenlighted there, and it is home to nearly 60% of electrolyzer manufacturing capacity. 
    • Outside of China, the electrolyzer manufacturing industry is seeing sharply lower revenues and higher losses, triggering bankruptcies and acquisitions that may signal an impending wave of consolidation. 
    • But Chinese electrolyzer manufacturers have different problems: Their manufacturing capacity far exceeds demand, and their less expensive products do not present a large savings to foreign customers once tariff, transportation and other costs are factored in. 
    • Policies to create demand for low-emissions hydrogen are expanding, but slowly; once created, they need to be supported by action. 
    • Project funding cuts announced in 2025 are likely to slow the expansion of low-emissions hydrogen in the U.S. in the short term. 

Based on the factors spelled out in the 288-page 2025 review, IEA offers leaders and policymakers a series of recommendations for low-emissions hydrogen, including: 

    • Maintain support for production, with a focus on shovel-ready projects that target existing applications — this would drive a faster upscale of production and enable cost reductions.
    • Create demand through regulations and support schemes in key sectors; collaborate with industry to create markets for end-use products to ease early-stage adoption. 
    • Expedite deployment of hydrogen infrastructure with regulatory frameworks and financial mechanisms that reduce risks for early investors. 
    • Add more efficient permitting processes and greater coordination among authorities that could help reduce lead times. 
    • Boost public finance mechanisms to reduce the risks associated with early-stage technologies that do not have a proven performance record. 
    • Help emerging and developing economies move up the value chain with new domestic uses and new export opportunities. 

There are many signs of diminished momentum, the report’s authors say. 

They note that the 2022 review found government policymakers had set a collective goal of 190 GW of installed electrolysis capacity at a time when not quite 700 MW was installed. 

“These ambitions set the bar very high for a nascent sector that needs to construct new value chains almost from scratch,” they write, and they detail the shortfalls. 

But they also detail the progress and say the signs of progress outweigh the setbacks: “While the challenges facing the hydrogen sector have led to slower-than-targeted deployment, a closer look at the evidence shows that — rather than stalling or faltering — the sector is progressing and reaching important milestones.” 

Posted on

PJM MIC Endorses 2 Quadrennial Review Proposals

The PJM Market Implementation Committee voted to endorse two packages of revisions to key parameters of the capacity market out of six offered by PJM and stakeholders that resulted from the Quadrennial Review. (See PJM Stakeholders Discuss Quadrennial Review Proposals.)

The Quadrennial Review resets the variable resource requirement (VRR) curve, which defines the amount of capacity the market procures and at what cost. The review also updates the reference resource technology class, currently a combustion turbine; the cost of new entry (CONE) for the reference resource in various regions of PJM; and the energy and ancillary services (EAS) offset, which estimates revenues outside the capacity market to net against CONE.

A proposal from LS Power received the greatest degree of support: 55.6% for both endorsement and preference over the status quo. It seeks to maintain the core design of the VRR curve while updating it for the changing economics of a CT. It adopts PJM’s initial recommendation of shifting the reference resource to a four-hour battery electric storage system (BESS) in the ComEd zone, which supporters have argued reflects the shorter expected lifespan of gas generation under the Illinois Climate and Equitable Jobs Act’s (CEJA) emissions requirements.

The package tinkers with the heat rate, variable operating and maintenance costs, and net summer ICAP attributes for the General Electric 7HA.03 turbine and added wet compression capability. The changes would result in the gross CONE decreasing by about 8% to between $613 and $630/MW-day of installed capacity, depending on the CONE area.

A joint proposal from PJM and Pennsylvania Public Utility Commission Vice Chair Kimberly Barrow was also endorsed, though it did not receive support over the status quo design. It included a CT reference resource for all zones, with the gross CONE between $592 and $679/MW-day, lower than the LS Power proposals.

PJM’s Skyler Marzewski said the rationale for using a gas generator in ComEd, rather than BESS, is that the falling effective load-carrying capability (ELCC) accreditation for storage is so sharp in the long-term estimates out to 2030 that a gas capacity resource remains more economic even with the truncated asset life. The proposal includes an adjustment to the asset life factor to reflect CEJA.

Staff opted to adopt elements of Barrow’s VRR curve to address uncertainty around CONE and EAS estimates. Rather than basing the price on multiples of gross and net CONE, the joint package sets the maximum price as the greater of 115% of gross CONE minus 75% of net CONE or 20% of gross CONE, which Marzewski said would avoid the maximum price collapsing to zero. The middle point would be defined as half of the maximum and the floor would be zero. The maximum would represent 99% of the reliability requirement; the middle would be 101.5%; and the floor 106%.

Like other proposals, the package would calculate the net EAS offset using forward-looking hourly energy and gas prices, but it would take the 67th percentile of calculated zonal values, which Marzewski said is meant to reflect that developers will seek to optimize their revenues when selecting where to site a resource.

The MIC’s votes were only indicative of stakeholder support. The two endorsed packages will be voted on along with the other four by the Markets and Reliability Committee and Members Committee at their meetings Sept. 25. The Board of Managers will ultimately decide on what revisions to propose.

Other Packages

A variant of the joint PJM and Barrow proposal swapped the CT for a combined cycle reference resource, resulting in a higher gross CONE, between $752 and $860/MW-day. The package did not receive endorsement, with a vote of 26.6% and 27.1% support over the status quo.

Marzewski said PJM prefers a CC reference resource, but its modeling of the two VRR curves in its proposals found there is not a huge difference in the results between a CT and CC under this design. A stakeholder process would be needed shortly after selecting a CC reference to mitigate the risk of the net CONE falling and causing a zero Capacity Performance penalty rate. PJM had sought to implement a CC reference resource in the fifth Quadrennial Review, but it reverted to a CT for the 2026/27 Base Residual Auction and the next auction because of concerns that the higher EAS revenues could lead to depressed capacity prices and knock-on effects on other parameters derived from net CONE, such as the CP penalty rate. (See FERC OKs Changes to PJM Capacity Market to Cushion Consumer Impacts.)

LS Power proposed a second package with the same CT and BESS reference resource characteristics as its initial package while reversing the VRR curve to the shape used in the third review, in place between 2014 and 2018, with adjustments to account for the ELCC accreditation and risk modeling paradigm. The maximum price would be set at the greater of gross CONE or 1.5 times net CONE divided by the accredited unforced capacity factor; the middle point would be 75% of net CONE; and the minimum would be zero. It received 43.9% support in the endorsement vote with the same for the status quo.

A standalone proposal from Barrow used a BESS reference resource in ComEd and a CC in all other zones and included a VRR curve similar to the joint proposal without the 20% gross CONE floor to the maximum price. It also did not include wet compression in the modeling of the CC reference resource. It received 21.3% support for endorsement and the same over the status quo.

The Independent Market Monitor’s proposal used a CT, without wet compression, for all zones with the gross CONE between $474 and $561/MW-day and a 20-year levelization except in ComEd, where it would be 15 years to reflect CEJA. The maximum price on the VRR curve would be the lower of gross CONE or 150% of net CONE; the midpoint would be half of the maximum; and the minimum would be zero. The quantities would be 99% of the reliability requirement for the maximum, 101.5% for the midpoint and 104.5% for the floor. It received 22.4% support for endorsement and over the status quo.

Posted on

PJM TEAC Briefs: Sept. 9, 2025

Update on New Jersey and Maryland SAA

PJM and the New Jersey Board of Public Utilities are in discussions on how the transmission and interconnection facilities planned for the state’s offshore wind aspirations can be put on ice in the wake of all the generation developers pulling out of their projects. (See N.J. Puts on Hold Remaining Pieces of $1.07B OSW Transmission Project.)

The RTO has responded to a BPU request to pause transmission planned under FERC Order 1000’s State Agreement Approach (SAA) by asking for clarification on what a “delay” means and to clarify that PJM requires amendments to the SAA and designated entity agreements for those tasked with developing the transmission. That includes new in-service dates for the OSW projects and a solicitation schedule for finding new developers for the generation.

PJM Senior Manager of Policy Initiatives Susan McGill told the Transmission Expansion Advisory Committee that the RTO’s request is not adversarial but meant to ensure that the BPU’s request can be fulfilled to the greatest degree possible without compromising reliability. She added that staff have also reached out to all entities involved in the SAA projects.

Planning staff have sorted through the SAA transmission to identify radial expansions with no impact on reliability, which can likely be deferred without issue, and multi-driver projects, which support both OSW interconnection and larger reliability needs or the interconnection of unrelated generation. Multi-driver projects may have to proceed regardless of the BPU’s request.

PJM is also processing a request from the Maryland Public Service Commission to use the SAA to support its goal of installing 8,500 MW of OSW by 2031. The two are working to draft an approach on how to proceed with the SAA, which would be PJM’s second, with the goal of the RTO completing its analysis and opening a competitive window for transmission projects in 2026.

The RTO has conducted an initial study on possible interconnection points based on the 2024 Regional Transmission Expansion Plan (RTEP) case, the results of which led the state to support a plan with five injection points. The scenario identified would begin with injecting 2 GW at Delmarva Power’s Indian River substation in 2028, followed by 3,500 MW in 2030 split equally between the utility’s Cool Springs, Piney Grove and Nelson sites. The last 2 GW would come online at PEPCO’s Calvert Cliffs substation in 2031.

McGill said PJM staff and transmission developers participating in the New Jersey SAA competitive windows found having two separate windows was disruptive to the RTEP process, so the intention going into the Maryland SAA is to have one solicitation and window.

PJM Presents RTEP Update

PJM is evaluating 134 proposals submitted, of which 57 are classified as greenfield and 77 as upgrades, in the 2025 RTEP Window 1 competitive window, which closed Aug. 18.

The projects also include grid-enhancing technologies, with five involving HVDC lines and five advanced conductor proposals.

PJM’s Matthew Wharton said there’s a need for solutions providing west-to-east transfer capability, with most of the corresponding submissions focusing on expanding the 765-kV backbone. Many of the 500-kV proposals focus on improving north-south flows within the eastern side of the RTO. The proposals are skewed toward higher-voltage solutions, both in number and cost, with 56 involving 500-kV projects and 29 at the 765-kV level.

Wharton said the projects have been reviewed for deficiencies, and PJM is waiting for responses from the submitters. Staff plan to review the proposals and pursue a first read on noncompetitive projects during the TEAC’s October meeting, with recommendations on competitive projects to be held throughout the winter. The RTO’s goal is to receive Board of Managers approval for a package in the first quarter of 2026.

Generation Deactivation Update

Vistra has notified PJM that it intends to deactivate two coal-fired units at its Kincaid generator with an installed capacity of 1,112 MW. The deactivation notice states that the company is seeking to bring the units offline by Nov. 30, 2027, to comply with the EPA’s coal combustion residual rule.

Milepost Power has also submitted a deactivation notification for its 31-MW gas-fired Forked River Unit 2 because of “its inability to meet New Jersey air permit requirements.” The company initially requested to bring the unit, located in the JCPL zone, offline on June 1, 2026, but shifted that out by one year.

PJM’s Michael Herman said staff have completed a reliability analysis on requests to deactivate Warren Evergreen CT 1 and Cooper Unit 1, together amounting to 121 MW, and did not identify any violations.

Supplemental Projects

AES Ohio presented a $74.1 million transmission project to serve a customer near Marysville, Ohio, seeking to ramp its load to 135 MW by July 2028; the customer plans to initially come online in February 2027 with 22 MW.

The project would construct a new 138-kV substation in a breaker-and-a-half (BAAH) configuration cutting into the 138-kV Millcreek-AD2-163 line and expand the Darby substation with a 138-kV BAAH yard. The new substation would be connected to Darby with a 5-mile 138-kV line. The project is in the conceptual phase with an in-service date in April 2028.

Duquesne Light Co. presented a $46.3 million project to fulfill a new service request seeking to bring 250 MW to Monroeville, Pa., with a projected in-service date in January 2029. It would construct a new 138-kV substation, named McGinley, in a BAAH configuration with 12 breakers and a 50-MVAR capacitor bank. It would be looped into the 138-kV Cheswick-Yukon and Springdale-Huntington lines.

PPL presented a $187 million project to serve a customer seeking to bring 300 MW to Gouldsboro, Pa., ramping to 1.5 GW in 2030. The project would construct a 230-kV BAAH substation, named Big Bass, along the 230-kV Pocono-Acahela line to connect to two 230/34-kV substations to serve the customer. The 230-kV corridor between Paupack-Pocono-Acahela would be upgraded with an additional circuit, which would also extend from Acahela to Jenkins and from Paupack to Callender Gap and Lackawanna. Several of the substations along the corridor would be upgraded with new bays and breakers to accommodate the additional circuit.

PPL also presented a $95 million project to serve a customer seeking 230-kV service in Hazleton, Pa., for a load coming into service in 2027 with 350 MW to ramp to 1 GW in 2030. The project would reconductor the 10-mile 230-kV Susquehanna-Tomhicken line and construct a new 230-kV line from Harwood, through Slykerville and to Tresckow. The new corridor would initially be single-circuit, with the intention of upgrading it to double-circuit. The Harwood, Slykerville, Tresckow and Nescopeck substations would be upgraded with 230-kV bays, and three 230-kV line terminals would be installed at Tresckow for the lead lines to the customer substation. A new 500/230-kV transformer would be installed at the Susquehanna 500-kV yard, and a 3.75-mile 230-kV line would be constructed from the 500-kV yard to Nescopeck, initially as single-circuit but to be upgraded to double.

Exelon presented a $590 million project to address issues aging and faulty equipment in the D.C. area by replacing the deactivated Champlain substation with a 230/69-kV station with gas-insulated, BAAH buses for both voltages and three 230/69-kV transformers. The Takoma substation would be upgraded with two 500-MVA phase-shifting transformers to control power flows and prevent overloads in N-1-1 contingencies. The work would create a new 69-kV source to the D.C. core and allow the L Street substation to retire. It would also enable the retiring of 11 oil-filled cables under the Potomac River that have seen operational issues.

Exelon presented a $84.8 million project to serve a customer seeking to bring 225 MW to the Hoffman Estates region of the ComEd zone in September 2028, with the expectation to ramp to 612 MW in 2031. A 345-kV substation, named Beverly Road, would be constructed with two 150-MVAR capacitor banks and a double ring bus to be expanded to a BAAH. The facility would cut into the 345-kV Libertyville-Tollway and Silver Lake-Wayne lines with two half-mile, double-circuit lines. The project is in the conceptual phase with a projected in-service date of Sept. 1, 2028.

Dominion Energy presented a $56.5 million project to construct a 230-kV substation, named Azalea Lane, along the Brambleton-Evergreen Mills line. The facility would serve load growth in Loudoun County, Va., with a requested in-service date of Dec. 31, 2029. The substation would be configured in a four-breaker ring.

The utility also presented a $20 million project to resolve a 300-MW load drop violation identified in the 2025 Do No Harm analysis, which would cause the Racefield and Reed Farm substations to be offline. The solution involves upgrading Azalea Lane and Reed Farm to six breakers and constructing a double-circuit 230-kV line between the two. The project is in the conceptual phase with a projected in-service date of Dec. 31, 2029.

Rappahannock Electric Cooperative has requested a new substation, to be named Matta, in Caroline County, Va., to serve a data center coming online on Dec. 1, 2026, and expected to ramp to 300 MW by 2031. The project is expected to cost $25.5 million, including $18.1 million for the substation and $7.4 million to cut into the Ladysmith CT-Kraken line.

Public Service Electric and Gas presented an $85 million project to provide relief for the Mount Laurel substation in New Jersey, which has a projected contingency overload of 115.3%. The solution would construct a 230/13-kV substation along the 230-kV Cox’s Corner-Burlington line and feature two 230/13-kV transformers. The project is in the conceptual phase with a possible in-service date in May 2031.

Posted on

PNW on Track to Meet Energy Savings Goals, NWPCC Finds

The Pacific Northwest is on track to meet energy efficiency goals set in the Northwest Power and Conservation Council’s 2021 power plan after having saved 160 aMW through improvements in 2024, the council said in a news release.

The 160 aMW in 2024 is up from 157 aMW in 2023. In total, the region has saved 465 aMW since the 2021 power plan was adopted in February 2022, putting it on track to hit the plan’s target of 750 to 1,000 aMW by 2027, the council stated in the Sept. 11 release.

“The council’s power plans protect the Northwest electricity grid’s reliability and adequacy, and cost-effective energy efficiency has been a crucial part of our strategy,” council board member K.C. Golden, who represents Washington, said in a statement. “The region is making key progress on our most recent plan’s target, but we have more work to do in the next two years. Acquiring the full target by 2027 will achieve the greatest benefit for the Northwest’s electricity grid and energy consumers in our region.”

Approximately 39 aMW of the 160 aMW in savings came from the Bonneville Power Administration, according to the news release.

The results are based on an annual survey conducted by the council’s advisory committee, the Regional Technical Forum. Participants in the survey include BPA, the Energy Trust of Oregon, the Northwest Energy Efficiency Alliance, and investor- and consumer-owned utilities in Washington, Idaho, Oregon and Montana.

Commercial buildings accounted for 50% of the savings in the 2024 survey, while the industrial sector accounted for 26%, the residential sector 22% and the agricultural sector 2%.

The region has increased spending on energy efficiency over the past three years. It invested $386.7 million in 2022, $456.2 million in 2023 and $580.6 million in 2024, the council said.

“This increase in funding comes after a period of declining investment in this resource,” according to the news release. “This trend likely reflects the renewed need for energy efficiency in meeting regional load growth. Budgets are forecast to grow by 12% in 2025, compared to 2024 levels. Continuing this trend will be important to achieving the 2021 plan’s full target by 2027.”

In total, the region has saved 8,042 aMW over the past 45 years, according to the council.

The savings report comes as the council prepares its ninth power plan, which will have a 20-year outlook for the region’s grid.

The council is required under the Northwest Power Act “to develop a plan to ensure an adequate, efficient, economical and reliable power supply for the region,” according to its website. NWPCC publishes a plan every five years, and the goal is to have a draft ninth power plan by July 2026 and a final version by the end of that year. (See NWPCC’s Initial Demand Forecast Sees Sharp Growth for NW.)

“The council’s power plans and collaboration with regional partners have made the Pacific Northwest a national leader in acquiring cost-effective energy efficiency,” Margi Hoffmann, Oregon council member, said in a statement. “Efficiency saves consumers and businesses money on their energy bills, makes our homes safer and more comfortable, and helps ensure the Northwest’s power supply continues to be adequate and reliable.”

Posted on

PJM Operating Committee Briefs: Sept. 11, 2025

Update on BGE Load Shed Event

PJM’s Kevin Hatch presented to the Operating Committee an update on the Aug. 11 load-shedding event in Baltimore, which brought 20 MW offline for about half an hour following equipment failures at the Brandon Shores substation. (See PJM: Baltimore Load Shed Caused by Tx Equipment Failure.)

Issues began to mount at the facility at 3:39 a.m. when the 230-kV Brandon Shores-Riverside line tripped, followed by the 230-kV line to Waugh Chapel coming out of service at 5:18 and a 230-kV bus tripping at Brandon Shores. At 5:56 another 230-kV bus tripped and the line to the Wagner substation went offline. At 7:39 a.m. the whole substation went offline after the transmission to Brandon Shores and a second 230-kV line to Waugh Chapel went offline.

PJM implemented several emergency procedures throughout the day, starting with calling 120-minute pre-emergency load management at 8:45 and the 30- and 60-minute products 15 minutes later. Demand response deployments lasted until 8 p.m. As load ramped up toward the afternoon peak, PJM called emergency load management at 2:15 p.m., instituted a 5% voltage reduction at 3 and directed load shed at 3:52.

Hatch said the load shed mitigated an N-5 cascade contingency that put about 1.2 GW at risk when load in the BGE zone exceeded 4.9 GW, which it was forecast to do at 3 p.m. before rising to a peak of about 5.2 GW at 6 p.m. The DR deployments brought load down by about 230 MW, with an additional 60 MW provided by the voltage reduction and 20 MVA from a few combustion turbines that were able to be brought online.

“We took all corrective actions we could to reduce risk to the system,” Hatch said.

A PJM graphic shows the timeline of issues causing the Baltimore substation to go offline on Aug. 11, leading to a 20-MW load shed. | PJM

Some PJM systems showed the emergency procedures as a trigger for a performance assessment interval (PAI), but Hatch said no PAI was initiated because of the localized nature of the event. He said the RTO is exploring changes to its reporting of emergencies to establish that a voltage reduction in a single zone does not automatically start a PAI, which would subject generation owners to Capacity Performance penalties if they underperform their capacity commitments. He said staff also plan to create a simulation of the event for future training.

Stakeholders Discuss PAI Triggers and Notifications

The committee discussed changes to revise the Emergency Procedures (EP) web app’s language around PAI triggers to reduce the possibility of users mistakenly believing a PAI is in effect.

Rather than simply specifying that an active PAI trigger is in effect, the app would state a potential trigger has been activated and point users to the Data Miner page of PJM’s website, which holds the “data of record” on when PAIs are and have been in place. References to PAIs also would be removed from EP email notifications sent to those who have enrolled.

PJM’s Chidi Ofoegbu said the aim is to have the changes implemented in October, but no firm date has been selected.

Several stakeholders argued the changes do not go far enough and would leave it up to individuals to delve into apps they are unfamiliar with to determine whether generators face penalties in real time.

Voltage-reduction Action Test Results

A test of PJM’s voltage-reduction action capability conducted on Aug. 14 yielded a little over half the load relief expected and demonstrated a need for additional reactive capability.

The test was expected to bring load down by 1.3%, which amounted to 1,852 MW when it began at 2 p.m. A reduction of about 1 GW was seen during the test, about 0.7% of load. Generator reactive capability fell during the duration of the half-hour test by 2,824 MVAR.

Hatch said there was strong communication between PJM and transmission owners throughout the test, and both continue to see value in conducting them twice a year. An additional TO also has communicated to PJM its interest in joining future tests.

Regular tests of voltage-reduction capability were among the recommendations PJM made following December 2022’s Winter Storm Elliott, during which the RTO was on the brink of implementing the first reduction action since the 2013/14 polar vortex. The first biennial test was conducted in August 2024. (See “PJM Conducts Voltage-reduction Test,” PJM OC Briefs: Sept. 12, 2024.)

Preliminary 2026 Capital Project Budget

PJM’s Jim Snow presented the RTO’s preliminary $65 million capital budget for 2026, which includes the purchase of two properties on the same block as its Audubon, Pa., headquarters. The budget is approved by PJM’s Board of Managers with input from the membership and Finance Committee.

The funding request is a $15 million increase over the 2025 spending forecast, which itself was an uptick from an average spending of about $40.3 million between 2019 and 2024. The preliminary budget is composed of $21 million for application replacements, $20 million for facilities and technology infrastructure, $19 million for current applications and system reliability, $4 million for interregional coordination, and $1 million for new products and services.

The purchase of 955 and 975 Jefferson Ave. in Audubon falls under facilities and technology infrastructure, which is increasing from $8 million of spending expected in 2025 to $20 million in the proposal. The category also includes replacing obsolete network and server hardware, as well as updating cybersecurity monitoring software.

Snow said the building purchases are likely to occur in the first half of 2026, depending on whether talks with the property owners are successful.

Application spending, which is flat from 2025, includes a new short-term load forecast model, replacing “critical” out-of-support software used in weekly and monthly settlements and continuation of the multiyear Next Generation Markets Systems project to upgrade the market clearing engine.

Snow said much of the current applications and system reliability spending is for multiyear projects, such as overhauling the Dispatcher Application and Reporting Tool.

Staff deferred requesting $3.8 million for optimizing the modeling of combined cycle generators in the budget, as well as $1.3 million for improvements to the Energy Management System and an additional $1.3 million for technology upgrades.

August Operating Metrics

PJM experienced an average hourly load forecast error of 1.37% in August and an average peak forecast error of 1.80%, according to an RTO presentation.

There were four days where over-forecasting exceeded the RTO’s 3% peak load error benchmark on Aug. 1, 6, 20 and 21. The first three were attributed to actual temperatures coming in lower than expected, while the 6.92% peak error on Aug. 21 was from “excessive temperature error” across several zones.

The month saw three spin events, one Energy Emergency Alert level 2 event, three pre-emergency load management reduction actions, one emergency load management reduction action, two high system voltage actions, two hot weather alerts and 25 post-contingency load relief warnings. Five shortage cases were approved, with three falling on Aug. 14 and two the following day because of ramping interchange, solar output falling faster in the evening than the load ramp and combustion turbines not coming online as scheduled.

The three spin events each fell below the 10-minute duration PJM uses to determine when it may back down a 30% adder on the synchronized and primary reserve requirement. Performance must be above 75% for the adder to be reduced by 10% and a larger reduction is possible if performance is higher. (See PJM OC Briefs: March 6, 2025.)

An Aug. 6 spin event had a 1,679-MW generation assignment, 69% of which responded, and 83 MW DR assignment, with a 42% response.

An Aug. 14 event had 2,855 MW of generation assigned, with 51% responding, and 538 MW of DR, 74% of which responded. An event the next day had 3,245 MW of generation assigned, 64% responding, and 454 MW of DR assigned, with 82% responding.

Cybersecurity Report

Delivering the monthly security report, PJM Director of Enterprise Information Security Jim Gluck highlighted a ransomware attack that used Anthropic’s Claude artificial intelligence software to target 17 organizations, including identifying network weaknesses, writing code used to bypass intrusion detection measures and obtaining individual credentials. Anthropic has published an article detailing how the attack was conducted and the guardrails it is developing to limit future potential, but Gluck said the use of AI continues to be a game of cat and mouse.

Gluck also recommended that stakeholders participate in a study researchers at the University of Pittsburgh are conducting to understand the barriers to additional cybersecurity spending, with the goal of creating a set of recommendations and a policy guide.

Posted on

PJM Preparing Alterations to Rejected CIR Transfer Proposal

PJM plans to modify and refile a proposal to revise how capacity interconnection rights (CIRs) can be transferred from a deactivating resource to a new unit after FERC rejected the tariff because of language that would have allowed developers to bypass the commercial operation date deadline (ER25-1128).

The proposal would create a nine-month process for PJM to conduct a replacement impact study on resources inheriting the CIRs from a deactivating unit and for an interconnection agreement to be offered. It would allow replacement resources to proceed through the expedited study process if minor network upgrades are identified and would not bar any resource class, thus allowing storage to receive CIRs. The revised tariff language will be brought to the Members Committee for endorsement Sept. 25. (See PJM Stakeholders Endorse Coalition Proposal on CIR Transfers.)

Stakeholders who supported the changes when the Planning Committee first endorsed the language in 2024 argued it would allow gas generators deactivating amid state clean energy policies to be replaced more quickly.

PJM Senior Manager of Interconnection Projects Jason Shoemaker told the PC that FERC signaled support for the overall proposal but identified two areas of concern: exempting resources with long development times from the COD requirement, and a one-time process for developers to request an indefinite delay for their CODs.

In its order rejecting the initial proposal Aug. 8, the commission faulted PJM for allowing developers to request a delay in transferring their CIRs without any time limit, which it said could allow resource owners to effectively withhold CIRs and create barriers to new entry. The commission said that undermines the RTO’s stated goal of allowing more resources to come online ahead of a capacity deficiency identified in the 2030 time frame.

“We find that PJM’s lack of a maximum time limit for the one-time option for an extension of a replacement generator resource’s commercial operation date regardless of cause renders PJM’s proposal unjust and unreasonable because it undermines the purpose of the generator replacement process,” the commission wrote. “That is, the main purpose of the generator replacement process is to avoid duplicative study costs and operational costs that otherwise would occur when the request to replace an existing generating facility must proceed through the interconnection study queue process, which will in turn avoid delaying the replacement of older resources with more efficient and cost-effective resources.”

The revised language would set the COD requirement at the greater of four years from when the developer submitted an application to construct a replacement resource, or three years from the requested deactivation date of the original resource.

Developers could request an alternative COD during the final agreement negotiation process, but they would have to demonstrate why the requirement should be shifted — akin to the milestone extensions permitted in the generation interconnection agreement process.

After the interconnection study is complete, developers could submit changes to the project to mitigate material adverse impacts and potentially reduce the network upgrades they are assigned. The submission would have to be made within 15 business days of receiving the study results and could be done only once. PJM would retool its analysis with the changes.

The commission also wrote that it saw the logic behind allowing generators with long development timelines some flexibility in their COD requirement but said the language could be ambiguous. While it did not cite that as a rationale for rejecting the proposal, FERC recommended that PJM include more specific language in any refiling.

“We also agree with PJM’s goal of offering replacement generation resources that face long lead times a certain degree of flexibility with respect to achieving commercial operation and agree that such resources ‘can make a significant contribution to meeting resource adequacy needs, at a time when PJM needs additional resources to maintain reliability,’” the commission wrote.

The COD exemption for resources with “industry-recognized significant construction time frames” was eliminated from the proposal.

Posted on

Ontario Market Monitor Revamps Techniques for IESO Nodal Market

Ontario’s energy regulator is learning new ways to identify inefficiencies and malign behavior under IESO’s Market Renewal Program, which introduced LMPs and a financially binding day-ahead market.

The Ontario Energy Board said its Market Surveillance Panel (MSP) has developed “new tools and indicia” in response to IESO’s nodal market, which launched May 1. (See Ontario Nodal Market Nearing ‘Steady State’ After Nearly 4 Months.)

OEB said the MSP will continue to track “market participant conduct and the efficiency and competitiveness” under the new market. “However, the complexities of the renewed markets have increased relative to the legacy markets,” it said.

The MSP, which transferred from IESO to the OEB in 2005, has three members: Chair Ken Quesnelle, former vice chair of the OEB and former chair of the Electricity Distributors Association; Brian Rivard, an adjunct professor at the Richard Ivey School of Business at Western University and a principal at Charles River Associates and IESO’s former director of markets; and Darren Finkbeiner, IESO’s former director of rule compliance and market surveillance. The MSP is supported by OEB staff and uses data provided by IESO’s Market Assessment Unit.

The MSP’s previous recommendations have been adopted by both the OEB and IESO — including some of the changes implemented under Market Renewal. MSP reports also have led to action by the IESO’s Market Assessment and Compliance Division, resulting in settlement repayments and financial penalties.

New Market: Locational Marginal Prices and Single Clearing

Under Market Renewal, day-ahead market (DAM), pre-dispatch and real-time prices are calculated at about 1,000 LMP nodes, instead of Ontario-wide. With a financially binding DAM, there now is a single dispatch schedule.

Here are some of the other changes under the new market, and how the MSP plans to respond:

    • Congestion Management Settlement Credit (CMSC) payments: CMSC payments encouraged participants to follow dispatch during transmission constraints under the former two-schedule system. They were replaced by LMPs — which embed the cost of congestion — and make-whole payments (MWPs), which compensate for lost opportunity costs when IESO dispatches resources out-of-merit.
      • While continuing to use the highest-cost peaking natural gas generators as an initial screen, the MSP also will use statistical models to identify anomalous LMP differences not explained by losses or congestion. “This type of monitoring analysis will replace the monitoring of legacy CMSCs to assess potential market flaws or inappropriate conduct not explained by grid conditions,” OEB said.
      • The MSP will monitor large MWPs, as well as MWPs to individual market participants or for specific facilities, to identify anomalous results or market manipulation. A new MWP Anomaly Index will put MWP levels in perspective relative to resource margins in the day-ahead and real-time markets. The index is calculated as: MWP ÷ (Resource Revenues + MWP) x 100. “This metric will tend to filter out changes in the level of MWPs due to variations in fuel costs … as well as those due to the frequency with which particular types of units are committed, to better identify potential anomalies and changes in behavior,” OEB said.
    • Reserve Shortage Penalties: IESO now is using reserve shortage penalty prices (a maximum operating reserve area penalty price, a penalty price for 30-minute operating reserve and an area minimum operating reserve penalty price) to ensure that day-ahead, pre-dispatch and real-time calculation engines respect mandatory reserve requirements, that prices reflect those requirements, and to encourage market participants to meet their reliability obligations.
      • The MSP will review all applications of reserve shortage penalty prices to identify the causes of the shortages and potential anomalies in market design or inappropriate market conduct.
    • Operating Parameters: The renewed market requires non-quick-start gas generators, hydro and variable generation to submit additional data on their operating parameters.
      • The MSP will monitor changes to individual facility data for their effects on dispatch and economic efficiency. “Changes to this data may be part of a broader strategy by a market participant to inappropriately influence market outcomes, MWPs and prices to the benefit of the participant [at the expense] of other market participants and consumers,” OEB said.

IESO Market Power Mitigation

IESO introduced a three-pronged market power mitigation (MPM) scheme to prevent suppliers from market power due to their location on the transmission grid:

    • An ex-ante (before-the-fact) approach applied in the day-ahead, pre-dispatch and real-time scheduling processes to police the energy and operating reserve markets.
    • An ex-ante mitigation process to prevent market power in the settlement of make-whole payments.
    • An ex-post (after-the-fact) mitigation of market power to address physical withholding and economic withholding on uncompetitive interties.

OEB’s surveillance unit will evaluate the effectiveness of the MPM framework through its own three-part market power screen: a conduct test (for withholding activity); a material price impact test (determining whether the conduct of a market participant significantly impacted market prices), and a profitability test (whether the MP’s conduct benefited the participant).

Market Control Entities

IESO will use data from market control entities — companies that control generators and other market participants (dispatchable and price responsive loads, electricity storage resources, energy traders or virtual traders) — to assess physical withholding by examining in aggregate the offer quantities of resources that share a common MCE.

Herfindahl–Hirschman Index of registered capacity per zone, 2019-2023. Except for the West and Southwest zones, HHI scores were greater than 1,800 throughout the period, indicating highly concentrated zones. | Ontario Energy Board Market Surveillance Panel State of the Market Report 2023

The MSP will incorporate the data in calculating structural measures of competition such as the Herfindahl–Hirschman Index and Residual Supplier Index.

OEB said the MSP will monitor persistent price differences between DAM and RT to ensure they are not a result of illiquid markets or gaming.

New Tool for IESO

To assess the effectiveness of the renewed markets and identify potential solutions to unintended outcomes, the IESO developed the Market Analysis and Simulation Toolset (MAST), which enables it to conduct “but-for” analyses of market outcomes through inputs into the market calculation engines.

OEB said the MSP also may use MAST in its assessment of the market’s efficiency in its annual State of the Market reports, as well as to analyze anomalous market outcomes and identify potential market flaws.

“In an upcoming State of the Market report, after sufficient data has been collected to permit such an analysis, the MSP intends to provide a comparison of the relative efficiency and competitiveness of the legacy markets to the renewed markets,” OEB said. “This analysis is not intended to be an audit of MRP at achieving its objectives. Instead, it is intended to offer insights into the overall efficiency implications of the changes, including where certain efficiencies may or may not have been realized and where improvements in design may be desirable.”