PJM on June 3 presented a first read of a proposal to revise how it determines whether generation interconnections are subject to state or federal jurisdiction based on voltage or cost-recovery methodology.
The proposal would introduce a “bright-line test” that would designate generators interconnecting to facilities below 69 kV as being under state jurisdiction and thus required to obtain a wholesale market participation agreement (WMPA). Resources connecting to higher-voltage assets would be designated as under federal jurisdiction and required to obtain a generation interconnection agreement.
The proposal also includes a “backstop” where a point of interconnection could be classified as federal or state jurisdiction independent of the voltage depending on how the transmission owner, FERC or relevant electric retail regulatory authority has determined the cost-recovery paradigm.
Presenting to the Planning Committee, PJM Associate General Counsel Thomas DeVita said the aim of the proposal is to maximize the hours staff spend processing the more complicated studies needed on resources connecting to transmission assets while still maintaining visibility on distribution-level interconnections. He said it takes staff substantially longer to process a GIA application compared to a WMPA.
Under the status quo “first use” model for determining jurisdiction, the first resource interconnecting to a distribution facility for the purpose of participating in wholesale markets is classified as being under state jurisdiction and required to obtain a WMPA. All subsequent resources using that point of interconnection are considered “dual use” and considered under FERC jurisdiction. DeVita said PJM’s model follows FERC’s approval of an ISO-NE proposal to disclaim jurisdiction over all distributed energy resources. (See FERC Approves Changes to ISO-NE DER Interconnection Process.)
PJM Vice President of Planning Jason Connell said system impact studies for a generator pursuing a WMPA are completed by electric distribution companies rather than the RTO and produce a simpler agreement for it to process.
Exelon Director RTO Relations and Strategy Alex Stern said it makes sense to make improvements to the interconnection process that have been demonstrated to be beneficial in other RTOs and could carry benefits for developers as well.
“Developers interconnecting at the distribution level might have less responsibilities at the regional grid level and in fact avoid certain responsibilities entirely, which could perhaps be a benefit to them on top of less process with PJM,” he said.
The proposal includes a dispute resolution process, beginning with the developer attempting to resolve issues directly with TOs and EDCs. If PJM determines a dispute involves its governing documents, the conflict could be arbitrated through the RTO’s tariff-defined resolution process.
If granted by the commission, DeVita said PJM is planning a go-live date in 2026 and anticipates that the Planning Community online portal could be updated to allow members to select facilities and determine whether a generator interconnecting at that site would require a GIA or WMPA.
PJM presented additional detail on the regional interchange and transmission violations that are expected to fuel need for transmission buildout in the first window of the 2025 Regional Transmission Expansion Plan (RTEP).
The competitive window for developers to submit projects addressing needs identified in Window 1 is set to open in mid-June and close in August.
Several large load additions have been submitted in the PPL region, while relatively little new generation is expected in the area, creating a need for new transmission to import power. The long-term seven-year case, which is used to right-size proposals brought for five-year needs, supports the conclusion that upgrades are needed to transfer energy between the Mid-Atlantic Area Council (MAAC) zone and PPL. Around 2.7 GW of load is expected near the Susquehanna switchyard by 2030, 1,400 MW near Juniata, 524 MW near Planebrook and 490 MW near Lancaster.
Large amounts of generation planned in the southern part of the Dominion zone likely will require upgrades to the 500-kV backbone running through the region. Additional upgrades also may be required on the 765-kV corridor running from northwest PJM to the AEP zone depending on how generation comes online.
Generation studied through the fast lane interconnection queue (around 300 projects that had minimal network upgrades identified), the 2.6-GW Coastal Virginia Offshore Wind (CVOW) project and the 1-GW Chesterfield gas generator near Richmond, Va., are expected to serve local needs and not drive significant changes to regional power flows.
The five-year case looking at 2030 finds PJM’s western region is expected to export almost 8 GW in the summer and 6 GW in the winter, down from the previous year in both seasons. Summer imports into MAAC would increase to about 3 GW. And while the region would remain an exporter in the winter, flows out were projected to decrease from 4 GW to 2 GW in 2030. Imports into Dominion would decrease in both seasons, falling from 6 GW to around 3.75 GW in the summer and from 10 GW to 6 GW in the winter.
Supplemental Projects
PPL presented a $159 million project to serve a new customer near Allentown, Pa., which is expected to bring 1,000 MW of load by 2031. The project would construct a new 500/138-kV substation, named Orefield, which would cut into the 500-kV line between Susquehanna and Wescosville. The 138-kV Oreville switchyard also would cut into the Wescosville-Siegfried 138-kV and Wescosville-Allentown 138-kV lines. Six 138-kV lead lines would extend from the 138-kV switchyard to the 138/34-kV substation serving the customer. The project is in the conceptual phase with a projected in-service date of May 30, 2028.
The utility presented an additional $89 million project to serve a new customer near Harrisburg, Pa., requesting service for 450 MW coming online by 2030. A new 230-kV switchyard, named Highspire, would be constructed along the Steelton-Hummelstown 230-kV line, which would be rebuilt as a double circuit. Three 230-kV lead lines would run to a 230/34-kV customer substation. The Hummelstown 230-kV switchyard would be expanded with new 230-kV bays as part of the project. The proposal is in the conceptual phase with a projected in-service date of May 30, 2028.
PPL presented a $73.5 million project to serve a new customer near Jermyn, Pa., seeking to bring 500 MW of load online by 2029. A new 230-kV switchyard, named Callender Gap, would be built along the Lackawanna-Paupack 230-kV line and serve a new 230/34-kV customer substation with three 230-kV lead lines. The line segment between Lackawanna and Callender Gap would be upgraded to double circuit. The project is in the conceptual phase with an in-service date of May 30, 2028.
PECO presented a $27 million project to build the Forge Spring 230-kV substation to provide 50 MVA of capacity to the distribution grid in the King of Prussia, Pa., area. The new facility would cut into the Betzwood-Barbadoes line and feature eight 230-kV breakers. It is in the conceptual phase with a projected in-service date of Dec. 31, 2029.
Dominion presented a $108 million project in Virginia to create an additional 230-kV supply to the Elmont-Fredericksburg corridor, which is seeing a large number of substations constructed to serve data center load. An existing supplemental project is planned to rebuild the Kraken-Elmont 230-kV line, which will establish double circuit structures and a 115-kV corridor between Fredericksburg and Elmont. The new project would install 230-kV conductor on the double circuit structures between Elmont and Kraken and use open arms of existing structures from Elmont to Chickahominy. The result would be two new 230-kV circuits from Kraken to Chickahominy. The project is in the conceptual phase with a Dec. 31, 2030, in-service date.
Dominion presented a $32.3 million project to serve a data center customer in Spotsylvania, Va., planning to bring 108 MW of load by 2028. The project would construct the 230-kV Tributary substation by cutting into the New Post-Ladysmith CT 230-kV line with 2.4 miles of new double-circuit lines. The project is in the engineering phase with a projected in-service date of April 1, 2027.
Consumers Energy filed a complaint with FERC against MISO seeking compensation for keeping open the J.H. Campbell coal plant this summer as ordered by the U.S. Department of Energy under Federal Power Act Section 202(c) (EL25-90).
The utility filed the complaint because MISO’s tariff lacks a method to ensure it gets paid for reversing the retirement of the 1,400-MW coal plant, which had been set to shut down May 31. Instead, Consumers has been bidding the plant actively into MISO’s markets and producing energy there when dispatched. (See DOE Orders Michigan Coal Plant to Reverse Retirement.)
The firm also said it has procured fuel, done review and planning for maintenance, and taken other steps to comply with the order. It has set up an account to track all those costs.
DOE’s order calls on Consumers and MISO to file any needed waivers with FERC to ensure the firm gets paid for keeping the plant open.
Consumers was not requesting any specific dollar figure in the filing, saying it will make a filing when DOE’s emergency order is over that explains the just and reasonable costs it incurred in running the plants, minus market revenues.
The utility and MISO agree the tariff lacks a mechanism for the utility to recover costs from complying with the order, and MISO cannot unilaterally offer the utility a rate agreement under Section 202(c). The utility asked for fast-track processing of the complaint and to make the compensation mechanism effective May 23, the date of DOE’s order.
“As soon as the DOE order was issued, Consumers Energy began incurring and will continue to incur costs to comply with the DOE order’s directive to ‘take all measures necessary to ensure that the Campbell plant is available to operate’ for the duration of the DOE order,” the utility said. “The precise order costs will not be known until after the DOE order expires on Aug. 21, 2025.”
FERC has the authority under Section 202(c) to approve compensation for any plants required to stay open under the law. That authority is supplemented by Section 309, which gives the commission the “power to perform any and all acts, and to prescribe, issue, make and rescind such orders, rules and regulations as it may find necessary or appropriate to carry out the provisions of this act.” That part of the law gives FERC the authority to set up rules for cost recovery before those costs are fully known, Consumers argued.
The utility said the costs should be assigned to MISO Zones 1 through 7, which make up the RTO’s northern and central regions, the reliability of which DOE said it was addressing with the order.
“Michigan load will of course pay its fair share of Consumers Energy’s order costs (net of market revenues) because, as the DOE order points out, MISO Zones 1-7 (i.e., the northern and central zones) include Michigan. But Consumers Energy believes that, whatever the order costs turn out to be after netting market revenues, they should be allocated beyond the state of Michigan,” it said. “Consumers Energy customers are already paying for the cost to fulfill the capacity needs of Zone 7.”
DOE’s order noted that while the plant’s retirement was approved by MISO, and Michigan has adequate supplies without it, the north and central zones still face elevated reliability risks this summer.
Beyond the FPA, the government is constitutionally required to pay Consumers for running the plant the summer, the utility argued.
“Specifically, the Fifth Amendment Takings Clause bars the federal government from taking private property for public use without just compensation,” Consumers said.
The utility filed its complaint under Section 206, but it said this was done to cover its bases. In the event FERC finds it lacks the authority under sections 202(c) and 309, it can find the MISO tariff unjust and unreasonable under 206.
“Consumers Energy will incur costs associated with the DOE order, but the MISO tariff does not presently include a mechanism that would allow MISO to compensate Consumers Energy for such costs or allocate those costs to load in the MISO region,” it said. “The MISO tariff is thus unjust and unreasonable as applied to Consumers Energy and its compliance with the DOE order, and the commission should order MISO to adopt a tariff revision to provide a cost recovery mechanism for Consumers Energy’s order costs net of market revenues.”
New England is unlikely to see the development of large-scale data centers in the next 10 years but likely will see smaller-scale developments, industry experts said at the New England Energy Conference and Exposition on June 5.
The region has yet to see major data center developments, largely due to high power prices. However, rising demand and capacity costs in PJM and MISO have caused some worries in New England about looming data center-driven load growth.
Even without a significant amount of increased demand from data centers, ISO-NE forecasts the region’s peak load to roughly double by 2050 due to heating and transportation electrification, which would require the region to add a massive amount of new generation and transmission capacity.
Representatives of companies developing large-scale data centers said they currently are not developing projects in the region, citing the high cost of power.
What drives interest in data centers is “where is there existing power and where are there existing customers,” said Judith Judson, senior vice president at Vantage Data Centers.
“In terms of operating costs, power really matters, and the price of power comes in substantially,” Judson said. “Power prices in the Northeast happen to be higher than in other parts of the country. But that doesn’t mean that this isn’t an area for growth.”
While load growth from data centers has yet to show up in New England, both Massachusetts and Connecticut have passed tax incentives in recent years to boost development. Massachusetts lawmakers in 2024 passed a bill exempting data centers from the state’s sales tax, while Connecticut allows data center developers to apply for an up-to-30-year sales and property tax exemption.
These incentives appear to have spurred some increased interest in data center development. In Western Massachusetts, the Westmass Area Development Corporation aims to build a $3 billion data center complex, though the not-for-profit development group has yet to announce anchor tenants for the project. In Connecticut, Dominion Energy has received requests from developers to co-locate data center facilities at the site of the Millstone nuclear plant.
“The amount of service requests we have in our service territory exceeds the peak load of Maine and New Hampshire combined, [though] we don’t know if these are real or speculative,” said Vandan Divatia, vice president at Eversource Energy. “We can enable some of these resources in a very strategic and measured way in various locations throughout our system.”
Morgan Steacy, vice president of connections and strategic accounts at National Grid, said the company has seen “some incremental growth” in data center connection requests after Massachusetts passed its incentives in 2024.
“Will we ever house hyperscalers? If I had to bet, no,” Steacy said, adding the state could see continued interest in smaller data center applications. She encouraged companies to reach out if they are interested in developing in the state, and that National Grid can help companies navigate the permitting and siting process.
Potential for Demand Flexibility
“The data center industry is not monolithic,” said Lucas Fykes, director of energy policy at the Data Center Coalition, noting the potential for demand response will vary significantly between different facilities.
He said demand response capabilities often depend on whether a data center is a single- or multi-tenant facility and it can be easier to reduce the load of a single-tenant facility, when the tenant can shift demand to a different facility.
Brendon Baatz, who works in energy market development at Google, said some of the company’s data centers have demand response capabilities and it is working to shift loads between facilities to minimize its overall emissions impact. He said this strategy is a key aspect of meeting the company’s goal of matching all its power demand with carbon-free energy on an hourly basis by 2030.
Judson of Vantage Data Centers said peak shifting “isn’t so much available” for the company’s facilities but added that “on very hot peak days, we can shift some to backup generation to take some of the load off the grid.”
Ultimately, as data centers come online, the facilities should not be treated any differently than other large sources of load, several speakers urged.
“It should be a very large customer tariff,” said Judson, who warned against overbearing interconnection requirements and called for collaboration among a wide range of stakeholders to establish rules for interconnecting data centers in a way that will both “serve our needs and protect ratepayers.”
“The answer to the question of whether we need a data center tariff is absolutely not,” said Baatz. “I do not think it needs to be specific to data centers, because there are other large loads coming onto the grid, and those should not be treated any differently than data centers.”
Rising demand means the U.S. needs to expand the transmission grid, and doing so also will keep power prices affordable, according to a report released June 9 by Americans for a Clean Energy Grid.
“We find that comprehensively planned, high-capacity transmission saves consumers money on electric bills, reduces congestion on the grid, unlocks access to lower-cost generation, avoids costlier investments in new generation or lower-capacity transmission and improves overall system efficiency,” the report says.
“Large-scale Transmission Deployment Saves Consumers Money,” prepared by Grid Strategies, says large-scale, proactive and collaborative planning and development are essential to savings for customers. Proper planning cuts costs by decreasing the need for generation and transmission investments overall, while allowing the grid to operate more efficiently.
“The affordability of electricity supply depends in no small part on the efficiency and cost effectiveness of the associated transmission expansion,” the report says.
Well-planned, high-capacity transmission could save residential customers $6.3 billion to $10.4 billion across the country after taking into account the cost of new power lines. Across all customer classes, the savings are estimated at $16.8 billion to $27.7 billion.
Transmission planners often underestimate benefits in their initial planning studies, and ex post assessments of consumers savings often are 20 to 40% higher. Applying that to potential annual savings for residential customers brings the range up to $8.7 billion to $14.4 billion, the report says.
Most of the estimated savings come from lower production costs, which means savings from lowering the cost of the power supply by accessing low-cost generation.
Investing in transmission as the report suggests would raise the transmission component of bills by 2% overall, which is a $19 increase annually. But that comes with a 3% cut in generation costs, which translates to $92 in savings annually for the average household.
The report based its estimates on annual savings in recent transmission planning efforts in several regions of the country, but that does not reflect the optimal buildout in doing well-planned, coordinated and cost-effective investments. Some regions are not engaged in that kind of planning at all.
“Extrapolating from a combined set of the recent portfolios planned by MISO discussed in this report, which are among the most robust examples of well-planned, high-voltage transmission, gives a better idea of the full savings consumers might see from more holistic, comprehensive transmission planning,” the report says. “This analysis reveals that every residential household in the country could expect over $100 in net savings on their annual electric bill if this type of planning were the norm nationwide.”
Beyond the savings, transmission supports a reliable, resilient and competitive power system, which benefits national security because of the race to develop artificial intelligence and the high-demand data centers it requires, the report says. A lack of transmission can delay electricity for consumers, slowing economic growth and jeopardizing national goals.
Expanding transmission also means more options to manage the uncertainties facing the power sector today, such as unpredictable load growth, volatile fuel prices, policy uncertainty, uncertain cost trajectories for costs of different types of generators and extreme weather.
“The reality is that price spikes can be crippling for electricity customers, even if they appropriately reflect market design and supply-and-demand fundamentals,” the report says. “As a commodity, electricity is different. It requires hedging and long-term planning that reflects the importance of the service to residential, industrial and commercial customers, as well as the relative degree of price inelasticity for American households. Well planned, high-voltage transmission investment is an essential piece of this puzzle.”
NEW ORLEANS — The 1,300 attendees who gathered in the Big Easy for Edison Electric Institute’s recent annual conference and thought leadership forum had little time for the city’s 24/7 nightlife.
They had a problem to solve: how to meet the biggest surge in demand since the post-World War II boom without raising prices for their customers.
Incoming EEI Chair Calvin Butler, Exelon’s CEO, said during the June 2-4 conference that the industry stands at “an exciting crossroad.”
“New challenges, historic levels of investment and burgeoning technologies like artificial intelligence are redefining America’s energy future,” he told the membership. “I look forward to working with EEI and its member companies to ensure that we continue to meet the evolving needs and expectations of our customers, while at the same time working to keep their bills as low as possible.”
“This is a remarkable time for our industry,” said Butler’s predecessor, Portland General Electric CEO Maria Pope, in opening the conference. “The extraordinary, once-in-a-generation demand for electricity is real, and it is here now.”
“It is remarkable the amount that we have invested in new technologies and resource adequacy,” she added. “We have seen our grid change at a pace and level that we have never seen before. We need to figure out how to get more out of the system while thinking differently.”
The U.S. Energy Information Administration said in January that the nation’s electricity consumption grew by 2% in 2024 and will continue to grow at that rate in 2025 and 2026. It will be the first three years of consecutive growth since 2005-2007, with much of the demand coming from battery manufacturing operations and data center consumption.
One of the key questions, of course, is how much of that demand will actually show up — that and whether there will be enough resources added to the grid in time to meet the demand. (See related story, FERC Dives into Thorny Resource Adequacy Issues at Tech Conference.)
“This is the question I was waiting for,” Amazon Web Services’ Vibhu Kaushik said during a panel discussion on increasing capital deployment to meet new demands from data centers, advanced manufacturing, electrification and large resilience programs.
“We’re all here together, and we are excited because this demand growth is real,” he said. “So why is the demand increasing? It’s increasing because customers today are using more technology than ever before. So yes, demand growth is going to go up.”
Asked the same question, Allen Otto, managing director of power, energy and renewables for Guggenheim Securities, said, “Nobody really knows, right?”
“Where we get concerned is not actually developing the assets to where we can unlock the economic potential that we have a number of industry areas,” he said. “There are a number of projections that are out there, and at the high end, they are 4% year-over-year power demand growth for all those reasons that we’re now familiar with. Even if it’s half that, it’s massive. It’s massive, and part of the issue is if we don’t move now, we’re going to have challenges even getting there. We don’t know exactly what the demand is going to be, but we do know that if we don’t act now, we’re going to fall behind our global adversaries and our allies, right?”
Congested generator interconnection queues don’t help. A recent Enverus study found that in 2024, new projects had spent anywhere from 9.2 years (CAISO) to 3.8 years (ISO-NE) in the queue, an average of 6.2 years per grid operator.
“Why do we have 2.6 TW of generation, a lot of carbon-free energy waiting to be connected to the grid?” Kaushik said. “Carbon-free energy that can be built in 18 months is waiting for five to seven years to be connected to the grid. Demand that could be connected faster to serve customers for essential services is waiting to be connected. The grid should eventually be a plug-and-play platform for all customers and all generators.”
Jeff Bladen, energy leader for Verrus, called for building out the grid, noting “there is no future” in which the industry benefits without “actually building stuff.”
“I’m a sellout for building as much transmission as we can get approved. We’re going to have to build more generation, right? At some point, you have to make electrons,” he said. “What I like to tell folks is that it’s important for us to get the most out of the grid we have while we’re building the grid we need, right? If we’re building large loads that are actually assets rather than liabilities, those will be assets for a very, very long time.”
Tricia Pridemore, a member of the Georgia Public Service Commission, said meeting the demand is the topic of conversation among state regulators “morning, noon and night.”
She said her commission was first exposed to the concept of data center demand in 2023 — just as Georgia Power was bringing the Vogtle nuclear plant’s third and fourth units to the grid at an estimated cost of $30 billion, more than double initial projections.
“[They] said, ‘But wait. We need more energy.’ You can imagine the five elected regulators just laughing them out of the office,” Pridemore said.
But after getting into the integrated resource plan’s process and meeting customers, the commission approved an IRP with 7.1 GW of new capacity in six months. Pridemore said it was the first IRP docket specifically developed for data centers and onshore manufacturing.
“We have before us right now another 1,500 MW of new capacity,” she said. “We’ve developed a construct that gets these customers involved, that gives them a seat at the table, but most importantly, they’re paying for it. We’re constantly trying to build out this required and necessary infrastructure. … We’ve got to be able to rise to this occasion, but we can’t do it off the backs of our residential rate payers. All 50 states have seen rates increase over the last several years, so now’s the time for us to be creative as regulators.”
Pridemore found a friendly voice in Louisiana Gov. Jeff Landry. He called for a “recalculation” of the regulatory environment, given the potential billions of dollars in new generation for his state.
“That’s the problem that we have to solve: How do we meet the demand without laying it on the backs of the consumer?” Landry said.
Southern CEO Chris Womack said utility work has to change in a future where technology and AI are likely to play such a huge role. He said lessons learned will be important because “we’re doing some things we never had to do before.”
The industry will have to navigate its way through construction, permitting reform, “the chaos in D.C. … all kinds of the tariffs and trade and just so many external factors that are coming into play,” Womack said.
“We will do this, but I think it’s so important for us to really understand the reality of what we face, and the reality that’s in front of us is going to be incredibly different,” he said. “The technology is going to keep moving so incredibly fast, it’s going to make us incredibly uncomfortable. We’ve got to … be comfortable doing incredibly uncomfortable things. … We’re going to have to keep pressing forward to meet this moment, to meet the challenge that’s in front of us. And we will, but I think it’s going to be so incredibly important that we find a way to do this together, to do this collectively.”
Industry Faces Tariff Uncertainty
The administration’s global tariff war is complicating the electric industry’s efforts to meet historic levels of increasing demand. During the final day of the conference, the government doubled tariffs on steel and aluminum from 25% to 50%. For an industry that relies on steel and other metals to build its generating plants and infrastructure, the result is obvious.
“A lot of other things we can sort of mitigate, but we use a lot of steel,” Occidental Petroleum CEO Vicki Hollub said. “And so when we have a lot of steel tariffs, it can really impact our industry and our cost structure.”
Hollub said her governmental and regulatory staff have been unable to provide clear answers on what to expect out of D.C.
“For the first time in my tenure as a CEO, I’ve heard our government guy come to our board meeting and say, ‘I don’t know’ to more questions than [having] thoughts,” she said. “We just can’t forecast right now. We’re trying to come up with lots of scenarios and evaluate the possibilities that, clearly, the largest impact on us would come if the steel tariff were to stay high.”
“The elephant in the room is what’s going on with the tariff policy,” said incoming EEI CEO Drew Maloney. “Everybody you know wants to understand how that’s going to impact their businesses here and how that impacts our traditional trade partners … how that’s going to impact business and sort of watching to see what happens.
“As we develop this more of an America First policy, what does that mean for Europe? Is Europe going to do more manufacturing going forward? Are they going to sort of reshore their supply chain?” Maloney added, calling for global collaboration with global trading partners “because that obviously is going to impact our energy growth that we’re going to have here.”
Maloney was appointed EEI’s CEO in April, replacing interim CEO Pat Vincent-Collawn, effective July 1. Vincent-Collawn, CEO of TXNM Energy and its two subsidiaries in Texas and New Mexico, replaced Dan Brouillette when he stepped away from the organization in 2024.
Maloney brings with him decades of legislative expertise from working on Capitol Hill and maintaining relationships with key lawmakers for various organizations. He served in the Treasury Department during the first Trump administration and as chief of staff for the House of Representatives GOP leadership.
Growing up on a farm in the Shenandoah Valley also prepared Maloney for work in D.C.
“I had to get up really early in the morning to make sure that all the animals were fed,” he said. “I had to clean out the stalls — great preparation for working in Washington, because there’s a lot of stall-cleaning in Washington.”
The Benefits of AI
While the growing reliance on AI could result in data centers consuming up to 12% of the nation’s power demands by 2028, speakers from the high-tech sector stressed the benefits of working with the technology.
Victor Peng, the recently retired president of AI developer AMD, said he was impressed with his audience’s willingness and desire to “meet this special moment in time.”
“I’ve heard from everyone here how collaborative this industry is, and that’s critical,” he said. “It’s encouraging to see people committed to understanding how to support AI. Really, it’s more than AI. This industry touches everyone’s lives on a daily basis and in every facet. The positive thing about AI is that it will affect everything.
“You should feel comfortable that this is not a bubble. The demand is real, and it will last for a really long time. And the pace that it is expanding at is daunting.”
“I think anyone who reads history understands that adaptability and harnessing new technologies is really the difference between success and failure,” Oracle CEO Safra Catz said. “It is without a doubt the difference between success and failure for companies, and it truly is the difference for countries and entire civilizations. There is no question that harnessing AI is widely recognized as a technical matter and a national security matter.
“This is the moment we’ve all been waiting for, using data to get better information to really help you all run your business. So, this moment is very, very important, and it’s going to be a challenge for a lot of folks to make the bold decisions of how do they move their technology to the 21st century. We’re already 25 years into it.”
Pausing for effect, Catz said, “The time is now.”
New Leadership for EEI
EEI’s Board of Directors elected Butler as chair for the 2025/26 cycle. The board also elected Womack and Evergy CEO David Campbell vice chairs. All three selections are effective July 1.
Butler most recently served the institute as a vice chair. The EEI’s chair rotates annually.
The three chairs appeared on stage together before the membership June 3 to share their thoughts on the coming year. Campbell, a lifelong Dallas Cowboys fan now leading a utility headquartered on the Kansas-Missouri border, wore a No. 3 Philadelphia Eagles jersey with Butler’s name of it, much to the delight of Butler and Campbell.
“Many of you were coming up to me saying, ‘Hey, what’s up with David wearing an Eagles jersey?’” Butler said. “I said, ‘I don’t know. That’s just David being David, and I’m flattered.’”
It became obvious who was the loser of a 2025 Super Bowl bet. As a reminder, Butler’s Eagles had no trouble with Campbell’s adopted Kansas City Chiefs, 40-22.
“Why number three?” Campbell said he asked Butler. “He said, ‘Because that’s my favorite number.’”
“But what do Eagles do? You know what you have to do,” Womack said, flapping his arms and encouraging Campbell to sing the Eagles’ fight song, “Fly, Eagles Fly.”
Campbell declined. However, he did complete his losing wager with a robust and quick “E-A-G-L-E-S, Eagles!”, half-heartedly punching the air with his right fist.
As the EEI’s host member, Entergy was given the honor of conducting the conference’s opening discussion, a conversation between its CEO, Drew Marsh, and Gov. Landry.
Entergy is seeking regulatory approval to build 2.4 GW of gas-fired power plants to service Meta’s massive data center in Northeast Louisiana. It’s about a $10 billion ask that also includes 100 miles of 500-kV transmission and eight 230-kV lines.
Marsh asked Landry whether the state can continue to attract large investments in the future. Given the opening, Landry responded without directly mentioning May’s load shed that knocked 100,000 Entergy customers offline. (See related story, NOLA City Council Puts Entergy, MISO in Hot Seat over Outages.)
“I mean, the question is, can y’all keep the lights on?” Landry said, drawing chuckles from the audience and a wan smile from Marsh.
Faces in the Crowd
Among the industry CEOs and regulators at the conference were former Louisiana Sen. Mary Landrieu, now a lobbyist but still exhibiting a master politician’s touch with reporters; former EEI CEO Tom Kuhn, now board chair for wireless communications company Anterix; PGE’s Pope chatting on the sidelines with Grid United’s Michael Skelly; industry consultant and Texas regulator Bob Gee, now a board member with the United States Energy Association; and Archie Manning, former quarterback for the New Orleans Saints and patriarch of the family’s quarterback dynasty, and his son Cooper, whose own football career was ended by a spinal condition.
The Mannings regaled their audience with their tales of Archie’s life in New Orleans and raising three boys who have quarterbacked four Super Bowl winners. Cooper’s son, Arch, is expected to be the NFL’s top draft pick should he leave the University of Texas early next year. By all accounts, Arch is just as grounded as his father and his more celebrated uncles.
“Clearly, I had an unbelievable mentor at home,” Cooper said, referring to his father. “I can’t tell you the number of times I’ve had to ask, ‘What would Dad do?’”
Archie, who was sacked 337 times during his 11-year career with the Saints (nine of which were losing seasons), told the story about being honored as one of the club’s 50 greatest players. During a banquet honoring the players, Manning, recovering from knee-replacement surgery, limped to the podium to say a few words. One of his “old” offensive linemen — “who, I assure you, was not one of the 50,” Manning said — offered to carry him up to the podium.
“I couldn’t help it. I said, ‘No, I don’t want to be carried, but if you and your buddies had blocked anybody out, I wouldn’t be like this,’” Manning said to laughter.
Edison International, Fortis Win Awards
Edison International and its Southern California Edison subsidiary won the 97th Edison Award for domestic companies and Canadian utility Fortis won the international Edison Award, presented annually during the conference.
Edison and SCE were recognized for the utility’s Advanced Waveform Anomaly Recognition system, which supplements advanced sensors and other applications already in service with state-of-the-art physics-based AI models and machine-learning technologies. The technology can help to identify and locate problematic equipment on SCE’s circuits before a failure occurs, mitigating outages.
Canadian electric holding company Fortis was honored for its Wataynikaneyap Power Transmission System project, the country’s largest Indigenous-led electric initiative. Fortis partnered with Wataynikaneyap Power and 24 First Nations communities to construct an 1,118-mile transmission line connected to 22 substations. The system connects 17 rural and remote First Nations communities to the Ontario provincial energy grid.
The Edison awards are chosen by a panel of former energy industry executives.
Amid increasing demand and dwindling supply, repowering aging fossil plants would help maintain reliability while still lowering emissions in line with New York’s climate change policy goals, NYISO argues in its annual “Power Trends” report, released June 2.
Repowering, or retrofitting, older units “can offer a bridge between old and new, the past and the future,” the ISO says. “Upgrading our existing fleet not only can help with a stepped approach to carbon reductions by replacing older, dirtier turbines with new, cleaner cutting-edge technology, it also holds the potential for helping avoid future generator breakdowns, therefore bolstering grid reliability.”
Much of the report repeats the same concerns as in the past few years: not enough renewables coming online to replace retiring fossil-fired plants, with large new loads being added to the grid at an accelerating pace.
“The grid is undergoing rapid and instrumental change,” NYISO CEO Rich Dewey said in a press release announcing the report. “We continue to observe declining reliability margins while forecasting a dramatic increase in load. It’s imperative during this period of transition that we maintain adequate supply to meet growing consumer demand for electricity.”
The ISO lists examples of repowering for different fuel types; for example, for wind resources, “replacing turbines with greater capacity or upgrading older blades with more efficient technology can improve energy yield.”
But it also notes elsewhere in the report that about 25% of New York’s total capacity consists of fossil fuel plants that have been operating for more than 50 years.
“As these fossil fuel generators age, they are experiencing more frequent and longer outages,” NYISO says. “Greater difficulties in maintaining older equipment, combined with the impact of policies to restrict or eliminate emissions, may drive aging generators to deactivate, which would exacerbate declining reliability margins.”
It goes on to say that “only New York’s existing fossil resources and certain hydro generators deliver the full array of services needed to balance a dynamic grid. Despite the need to reduce fossil fuel use to meet the state’s emissions-reduction targets, some level of fossil-fired generation will be needed for reliable power system operations until the capabilities they offer can be provided by other resources.”
But the NYISO Market Monitoring Unit noted in its State of the Market report for 2024 last month — and as New York regulators have acknowledged — development of new renewable and storage resources is severely lagging the state’s targets. The Climate Leadership and Community Protection Act (CLCPA) required a 70% clean generation mix by 2030, a target officials have admitted likely already is out of reach. (See N.Y. Moves to Boost Lagging Clean Energy Development.)
“While over 14 GW of Tier 1 awards have been announced under the [Clean Energy Standard], just 9% have entered service, while 61% have been canceled, and most of the remainder have not yet moved forward with construction,” the MMU wrote. Among the reasons listed for the delays and cancellations are weak nonperformance penalties, giving developers increased incentive to submit more aggressive bids. “Consequently, awards are more likely to go to projects that are relatively unlikely to be constructed.”
The report “clearly demonstrates that the time for state action is now,” Gavin Donohue, president of the Independent Power Producers of New York, said in a statement. “Energy consumption will continue to increase as New York strives to achieve its electrification goals, and that will require a diverse energy portfolio, as well as modernized generation units. This report further proves that the aging units and repowering opportunities need to be addressed as they are critical components of New York transitioning to a cleaner energy future in a reliable, affordable and responsible fashion.”
The opening of Ontario’s new market has been marked by real-time volatility and unusually high operating reserve (OR) prices.
“They seem to be burning through their ancillary service reserves,” said former trader Jake Landis, director of solutions engineering for Yes Energy. “[It’s] almost as if they aren’t carrying enough reserves in general.”
“100%,” agreed Brady Yauch, director of markets and regulatory for Power Advisory. “The ancillary services market is just really tight right now … although energy we’re very long.”
Between 2021 and 2024, Yauch said, 10-minute spinning reserve (10S) prices in the first two weeks of May ranged from $6 (2024) to $19/MW (2022). In the first two weeks of May 2025, the average day-ahead price has been $30/MW, with real-time prices averaging $51/MW. “So there’s a huge difference,” Yauch said.
At an IESO webinar June 4, Yauch asked whether the higher OR prices were a short-term phenomenon or indicative of a structural change as a result of Ontario’s Market Renewal Program, which implemented a financially binding day-ahead market and switched from zonal to nodal pricing on May 1. (See IESO Opens Day-ahead Market in Nodal Rollout.)
Northwest Ontario has seen big spikes in real-time prices since IESO introduced nodal pricing May 1. | Power Advisory
Darren Matsugu, director of markets, responded that the OR price trend was a springtime issue, citing “freshet,” the annual influx of water from spring rainfall and melting snow. Many hydropower projects must exit the OR market and operate as “must run” generators in spring because they have to flow the excess water through their turbines.
“It happens every May — this year, even more than perhaps other years — the amount of reserve available from those hydroelectric resources is less than normal,” Matsugu said.
At the same time, natural gas generators are less likely to be committed and online during times of low demand. “And so naturally, that puts a scarcity in the amount of operating reserves that we have available on the system under these types of conditions,” he added. “As we get further into the summer, both as far as the hydrology — but also we have more other resources committed and online that can provide operating reserve — we expect that to stabilize.”
Yauch acknowledged that thin OR supplies are typical in the spring shoulder period. But he said OR prices this May appear to be affected by a change in the supply stack, with the introduction of an operating reserve demand curve. In the legacy market, IESO used a voltage-reduction offer in the OR supply stack — what Yauch called “fictitious supply.”
“Ultimately, the supply and demand on the system create the pricing outcomes observed, including over the last month,” IESO spokesperson Andrew Dow said in an email to RTO Insider. “Market Renewal delivered many improvements to how energy and OR co-optimization produce prices in the market, including but not limited to introducing an OR demand curve. All of these improvements work together to create better alignment between the pricing outcomes and the underlying system conditions and resource availability.”
Between 2021 and 2024, 10-minute spinning reserve prices in the first two weeks of May ranged from $6/MW to $19/MW in Ontario, well below prices for the first two weeks of May 2025. | Power Advisory
IESO says the MRP should save Ontario $700 million over the next decade through reduced out-of-market payments and increased efficiency.
NERC and the Northeast Power Coordinating Council require IESO to provide OR equal to the largest single contingency plus half of the second-largest contingency — equivalent to the loss of Ontario’s one-and-a-half-largest generators.
IESO buys three types of operating reserves from dispatchable generators and loads: 10-minute synchronized (spinning); 10-minute non-synchronized (non-spinning); and 30-minute non-synchronized. OR providers must be able to respond within the 10- or 30-minute time frame and provide energy for up to one hour.
LMPs
Yauch said the increase in OR prices was the biggest surprise so far from the new market. He said he was not surprised by the volatility of real-time energy prices in the first weeks.
The real-time hourly Ontario Zonal Price (OZP) — the load-weighted average of all LMPs in Ontario — rose above $100/MWh almost every day in the early weeks, “which is well above the marginal cost of a typical thermal resource in Ontario,” Power Advisory said in a note to clients May 16. “In total, there were 19 hours where the price was greater than $100/MWh last week, compared to eight in the first week in May and zero hours in the equivalent week in 2024, when the uniform price was still determined by the Hourly Ontario Energy Price (HOEP).”
Day-ahead zonal prices averaged $19/MWh for the second week, versus a real-time average of $38/MWh, Power Advisory said. The Northeast and Northwest zones saw much higher congestion and transmission losses than southern Ontario, as was expected, it said.
Yauch called it a “tale of two grids,” with southern Ontario experiencing limited congestion and the north choked by a large number of hydropower facilities and dwindling mining and industrial loads to absorb the supply. “They can’t get the energy out,” he said.
The first two weeks also saw a lot of volatility in the west near Windsor. “That was a surprise, but it’s died down,” Yauch said.
Nuclear Impact
A derate to the Bruce Nuclear Generating Station on May 12 caused real-time prices in southern Ontario hit the price ceiling of $2,000/MWh, with the Ontario Zonal Price rising to $778/MWh in the 8-9 p.m. hour. | Power Advisory
Hydropower isn’t the only generation source affecting Ontario’s market. The province also has more than 12,000 MW of baseload nuclear capacity. Combined, nuclear (53%) and hydropower (25%) constitute more than three-quarters of IESO’s fuel mix, up from 66% in 2003.
On May 12, three units at the Bruce Nuclear Generating Station were de-rated beginning in the 8-9 p.m. hour, causing real-time prices in southern Ontario to hit the price ceiling of $2,000/MWh, with the real-time OZP rising to $778/MWh.
[Editor’s note: RTO Insider became part of Yes Energy in March 2025.]
PORTLAND, Ore. — Panelists at the annual meeting of the Western Conference of Public Service Commissioners emphasized the need for innovative regulatory frameworks to keep up with new technology.
Jay Griffin, senior adviser at the Regulatory Assistance Project and former chair of the Hawaii Public Utilities Commission, said electric industry participants in the U.S. should look to their counterparts in the United Kingdom.
After having visited the U.K., Griffin said, “one of the striking things there was how much quicker the pace of interconnection is for large loads and generation resources.”
Griffin made the comments at a panel discussion on technology adoption rates and regulatory reform during the WCPSC session June 2.
Griffin noted the U.K. has leveled the playing field of interconnection in part by having an open-source map that updates real-time capacity throughout the entire network and by making the pre-application connection assessment easier through a publicly available web app.
“They’re bringing resources online much faster,” Griffin said. “The tradeoff there is some level of curtailment over time, but that’s in exchange for bringing projects online years faster.”
Another key to the puzzle is that the U.K. uses performance-based regulation (PBR), according to Griffin.
PBR is a way to align utility incentives with the interests of customers and society. Traditional regulation pays utilities for what they build, while PBR focuses on what they achieve, according to a report issued last year by RMI.
PBR still is in the “nascent phases” in the U.S. — and in the Pacific Northwest, said Lauren McCloy, policy director at the Northwest Energy Coalition.
Still, the fact that PBR is being discussed as a way to address public needs and bring new technologies online is encouraging, McCloy said.
To implement PBR in the U.S., regulators should start “with a broad-based conversation about what are the policy goals that we’re trying to achieve,” according to McCloy.
“What are the technologies that are available to try to achieve that? And then, what are the incentive structures within cost of service-based regulation and maybe, you know, other frameworks that we could adopt to make that technology both more accessible, more transparent and deliver more benefits to customers.”
However, Elliott Nethercutt, senior director of state regulatory affairs at the Edison Electric Institute, urged caution.
Nethercutt said the existing regulatory framework is designed for reliability and affordability.
“I think that we got to move faster, but we don’t want to throw out the baby with the bathwater,” Nethercutt said. “We just need to see how we can make things … work and move a little more efficiently.”
Pilot programs, future test years, cost trackers and multiyear plans, among other alternative approaches to regulation, “can really move things faster and really meet the needs of electric companies and their customers in an era of rapid load growth,” according to Nethercutt.
Risks of Inaction
In a separate panel, Michele Beck, executive director of the Utah Office of Consumer Services, similarly stated that the industry must take a cautious approach when implementing new technology and updating planning processes.
“I understand there’s new times, and we need new solutions, but … the solution is not to put risk on customers,” Beck said.
Beck also noted “maybe we need a pilot program” to temporarily step outside the current “least-cost, least-risk paradigm.” This would allow regulators to look at cost allocations and augmentations to planning processes “to make sure that we’re treating all the resource types fair,” Beck added.
Meanwhile, Mark Thompson, a former Oregon utility commissioner who now is Form Energy’s senior director of state affairs, said while it’s a fair question to ask about the risk to ratepayers, regulators also should ask “what are the risk of not doing a new technology?”
“If the future is very different from the past, and we see all these constraints, and we have new challenges, and we have a new need for resources, there’s significant risk for ratepayers of never figuring out the new technology,” Thompson said. “These new technologies need a pull from the market. They need a pull from utilities who are willing to be partners, and they need a pull from regulators saying, ‘we’re willing to try something with you. Let’s figure out what it is.’”
California is setting records for the amount of battery energy storage operating on its grid, but in one Southern California beach county, residents have come out in large numbers opposing a proposed battery facility because of fire safety concerns.
The proposed Compass Energy Storage Project would operate as a 250-MW facility in San Juan Capistrano, near Laguna Niguel and Laguna Beach. California now has more than 12,000 MW of battery storage operating on its grid.
The project is under review with the California Energy Commission, specifically the CEC’s Opt-In Certification program, which began in 2022 as part of Assembly Bill 205. The program’s permitting process offers “developers an optional pathway to submit project applications, facilitating faster deployment of renewable technologies,” the CEC said.
Most residents and government officials in opposition are worried about a fire at the facility and the release of toxic chemicals. Laguna Niguel, for example, is located directly downwind of the project site during offshore winds, which not only occur during Santa Ana wind events but also on most nights, especially during the winter months when the inland valleys cool more than the ocean, the city said in comments filed with the CEC.
Laguna Niguel officials pointed to the Moss Landing battery storage facility that caught fire in January 2025 and required the evacuation of approximately 1,200 people within an eight-mile radius. A fire at the proposed Compass Energy Storage facility would require the evacuation of more than 37,000 people in a two-mile radius alone, the city said. An eight-mile radius could require 100,000 or more people to move out, the city said.
In response to safety concerns, Brett Fooks, CEC manager of safety and reliability, said the Moss Landing facility has two different safety characteristics compared with the proposed Compass Energy Storage project. First, the Moss Landing batteries are nickel magnesium cobalt lithium-ion batteries. This type of battery is more prone to thermal runaway than is the Compass battery, which would use a lithium-ion phosphate chemistry, Fokes said.
Second, the Moss Landing batteries are located indoors, whereas the Compass project’s batteries would be located outdoors. Indoor battery facilities are less fire-safe, Fooks said.
Objective Review
Not all local parties oppose the project. The Orange County Hispanic Chamber of Commerce offered support in comments to the CEC. The permanent shutdown of the San Onofre Nuclear Generating Station, combined with San Diego Gas & Electric’s forecast of a doubling in energy demand by 2045, underscores the importance of this initiative, the chamber said.
“The Compass facility will play a critical role in storing renewable energy and ensuring its availability during periods of high usage,” the chamber said. “In addition to its environmental contributions, the project is expected to provide over $50 million in local tax revenues, directly benefiting public schools, infrastructure development and community safety.”
The CEC currently has three projects with completed applications in its Opt-In Certification program, CEC staff told RTO Insider. The first project, Darden Clean Energy, has been recommended by staff for approval and will be considered by the commissioners at a business meeting June 11.
The second project, the Fountain Wind project, has been delayed beyond the 270-day timeline in alignment because of significant changes to the project discovered during development of the environmental impact report. CEC staff have recommended against the Fountain Wind project, which is anticipated to go before the commission at a business meeting in August or September, CEC staff said.
The CEC plans to vote on the Compass Energy Storage Project near January 2026.
If approved, the facility would interconnect into the existing SDG&E Trabuco-to-Capistrano 138-kV transmission line, which is about 500 feet from the project site. The project would connect to the transmission system through a “loop-in” transmission line. No downstream upgrades or off-site transmission upgrades are required for the proposed project, CEC staff said.
The CEC does not decide on the location of energy projects in California, leaving that to developers, CEC Executive Director Drew Bohan said at a May 29 public meeting.
“We evaluate projects when the [developer] applies,” Bohan said. “We then make recommendations as CEC staff to the CEC … about how they should dispense with the proposal.”
“I want to make clear that the CEC does not advocate for or against any proposal. Instead, we review each application objectively … on safety, environmental standards and community feedback,” Bohan said.
