Artificial intelligence, once envisioned only in science fiction, is becoming commonplace in our offices and homes. Ironically, the AI-enabled features of a modern world — from internet searches to chatbots to digital assistants — are all powered by an energy system that has been going strong for over 100 years.
Just as AI may be the most significant technological advancement of this millennium, the energy grid was the most important engineering achievement of the last. It was built to last, and while the way the world produces power has evolved, how energy flows — from power sources then over poles and wires to our homes and businesses — is largely unchanged from when the system was designed.
What has dramatically changed is the demand on that system. Exelon has a number of high-potential data center projects in our pipeline that together would require 11 GW of additional load. To put that in perspective, 1 GW can power close to a million homes. As an example of the magnitude of data center development that already has taken place, in the Chicagoland area alone, Exelon helped launch 20 data centers over the past two years.
We have been modernizing and strengthening our energy grid to meet residential, small business and commercial customers’ electrification needs, and like much of the technology to which we have grown accustomed, the grid has gotten smarter and more complex. Our smart grid provides many benefits to our operations and customers, including the ability to automatically reroute power when there’s damage, improving reliability by shortening repair time and reducing customer outages.
As AI advances, it will bring even more benefits to the energy system that powers it, including predictive maintenance, bolstered cyber security and enhanced employee training. In turn, the grid will be more efficient, more reliable and better able to meet AI’s energy demands.
Exelon is proud to support the expansion of the data centers that house the computer systems, servers and storage needed to sustain AI. We see data centers as key partners, and we are committed to supporting their growth and development, while also meeting the increasing demands for sustainable and reliable electricity.
Collette Honorable | Exelon
Recent proposals for co-location, a practice in which data centers are built next to a power plant, have gained attention, with FERC convening a technical conference on the subject Nov. 1 and rejecting as unsupported a precedent-setting interconnection agreement involving a data center and a nuclear generator. That agreement, which did not conform to standard terms, would have raised electricity bills for residential and other customers.
If data centers are connected to the grid — even if their first point of connection is a generator — they should contribute to the cost of the network infrastructure providing those services. Most data centers do just that. However, if co-located data centers are not recognized as network load, we estimate the annual electric bill for residential customers in the surrounding region could increase by up to $214.
Co-locating with an electricity generator also presents important considerations for the data center on how dependent they want to be on a single generator — rather than the entire electric grid — for reliable service. At the FERC technical conference, an advocate for co-location acknowledged this dependence may not be the best choice for a data center running defense critical services given the risk.
Co-location presents an opportunity to support the ongoing nationwide energy transformation and promote economic development in the communities we serve. We are proud that Site Selection magazine once again named two of our local energy companies, ComEd and PECO, to their 2024 list of the “Top 20 utilities in economic development,” based on the number of facility investment projects attracted to their service areas, the capital investment and potential for job creation.
We also agree with the Biden Administration’s desire to operate data centers within U.S. shores, mitigating concerns about foreign control of these critical assets. It is important then to understand and be clear: this effort can and will continue, and we will help facilitate it.
We are committed to continuing our work with data centers to meet their needs, no matter where they are located. And, even with demands that far exceed what the energy pioneers may have envisioned, the energy grid of today is ready to meet the moment, just as it was a millennium ago.
Exelon looks forward to continuing to lead the energy transformation, with future generations in mind, in a way that is equitable for all our customers and communities.
Colette D. Honorable is Exelon’s EVP of public policy and chief external affairs officer.
Former Southern California Edison Senior Vice President Erik Takayesu will join MISO’s Board of Directors beginning Jan. 1 after a vote among its membership.
Johnson was allowed to stand for an additional three-year term beyond MISO’s customary three-term limit through a waiver of its bylaws. MISO’s board uses waivers to retain institutional knowledge on the board when necessary.
MISO’s board members and membership decided they needed to hang onto Johnson’s system planning expertise after it warned that in addition to departing Director Phyllis Currie, other current board members H.B. “Trip” Doggett, Barbara Krumsiek and Todd Raba would hit their three-term limits at the end of 2025. (See Extensions Likely for MISO’s Term-limited Board Members.)
Lange was up for re-election for her third and final term.
MISO’s board elections require candidates to earn a majority of votes in support among membership. Members can vote for or against or can abstain from selecting any of the candidates. The elections require a minimum 25% participation among MISO’s approximately 140 voting-eligible members to achieve quorum. The RTO again used VoteNet Solutions to conduct its monthlong membership vote of the candidates.
MISO’s board and leadership praised Takayesu’s appointment.
“The continued service of directors Johnson and Lange provides continuity as we manage the changing energy landscape, and Director Takayesu has a wealth of industry experience to help solve the complex problems we’re facing,” MISO CEO John Bear said in a press release. “Overall, our board members bring a cross-section of knowledge to steer us in the right direction.”
“Director Takayesu is a welcome addition to the board, and directors Johnson and Lange will continue to provide key insight and institutional knowledge as we navigate the energy transition,” MISO Board Chair Todd Raba said. “We appreciate Director Currie’s leadership during her tenure on the board. Her steady guidance served as a model for her fellow directors.”
While at Southern California Edison, Takayesu led the utility’s business and asset management strategy, system planning, technology demonstration and development and wildfire safety. Takayesu currently serves as a member of the Department of Energy’s Electricity Advisory Committee.
The Board of Directors will meet for a final time this year Dec. 12 as part of MISO Board Week.
The Tennessee Valley Authority has approved a power purchase agreement with Elon Musk’s xAI supercomputer facility in Memphis.The facility is expected to use up to 150 MW at peak. Any company using more than 100 MW requires TVA approval.The facility is online and using temporary gas turbines for power.
FERC Gives Venture Global Permission to Introduce Natural Gas into LNG Plant
FERC has approved Venture Global LNG’s plans to introduce natural gas into its Plaquemines export plant in Louisiana.The company can commission and introduce natural gas into its “fuel gas and warm flare” systems, FERC wrote in its order. It is allowed to introduce gas to other parts of the facility once the company complies with the conditions of the order.The 20 million metric tons per annum Plaquemines LNG plant will be the second-largest U.S. export facility when fully operational.
CenterPoint Receives Recommendations Over Beryl Response, Hires Emergency Preparedness and Response VP
PA Consulting Group, the independent third party responsible for reviewing CenterPoint Energy’s response to Hurricane Beryl, made 77 recommendations aimed at improving the company’s readiness, response and communication during future storms and/or emergency situations.
So far, CenterPoint said it has completed 18 of the recommendations and is in the process of completing 33 more. The company said it would evaluate the remaining 26 as it continues to formulate its long-term resiliency efforts that will be announced next year.
CenterPoint also hired Don Daigler to oversee a revamp of its emergency preparedness and response. Daigler, founder and CEO of Resilience Advisory Services, a consulting firm specializing in resiliency across critical infrastructure sectors, will join the company as its senior vice president for emergency preparedness and response in mid-November.
Spain’s Acciona Energia announced the acquisition of two wind farms in Texas totaling 300 MW.The company paid $202.5 million to buy the Green Pastures I and II wind farms from various private asset management entities.
Enlight Renewable Energy’s U.S. subsidiary, Clenera, announced it has signed a 20-year power purchase agreement with Arizona Public Service for its Snowflake A Project.The project, which will provide 600 MW of solar and 1,900 MWh of storage availability, is expected to be operational in 2027.
Southern California Edison has enacted public safety power shutoffs and cut off power to tens of thousands of customers due to heightened wildfire risk.The extreme wind event generating 70-to-80-mph winds ignited two fires around Santa Ana.Shutoffs, which had affected Los Angeles, San Bernardino, Riverside, Ventura, Orange and Santa Barbara counties, were extended into parts of Kern and Tulare counties.
Voters approved $10 billion in bonds for climate and environmental projects.Proposition 4 will fund projects to safeguard drinking water, combat wildfires, protect natural lands, and improve resilience against floods and extreme heat. Water projects will get about $3.8 billion. Half of that portion, $1.9 billion, will be spent on improving water quality, while the rest will be spent on protecting the state from floods and droughts and restoring rivers and lakes.
The Board of Weld County Commissioners voted 4-1 to approve a solar farm.The project, which is being developed by Balanced Rock Power and Taelor Solar, will sit on 4,300 acres in Weld County and 4,100 acres in Morgan County.The project had gained approval from Morgan County and the Weld County Planning Commission.
Xcel Energy Ordered to Remove Investor Relations, Exec Salaries from Customer Costs
The Public Utilities Commission ordered Xcel Energy to remove all investor relations costs — including a portion of executive salaries — from its calculations of costs passed on to customers.Following the 2022/23 winter, the legislature convened a special committee to investigate rates. The result was Senate Bill 291, which took aim at 15 types of expenses that should not be paid by customers, such as a portion of board of directors’ compensation, travel and entertainment expenses. In a current gas rate case, more than $775,000 in such costs were disallowed.
The Siting Council has approved a $3.75 million solar facility in Enfield.Lodestar Energy will develop the 1.93-MW solar facility on 12.1 acres of unused farmland.Construction is expected to take between six to nine months.
The Utility Regulatory Commission has cleared the way for AES Indiana to transition two units at its Petersburg Generating Station from coal to gas.The repowering of Petersburg Units 3 and 4 will be staggered so that only one unit is offline at a time. Unit 3’s conversion is expected to start in February 2026 and be completed in May 2026. Once completed, it will take about one month for startup, commissioning and testing to reach a commercial operation date in June 2026. Unit 4’s outage would start in June 2026 and be completed in October 2026.The move is expected to save $281 million over 20 years.
The evaluation team that includes the Department of Energy Resources, National Grid, Eversource and Unitil has informed the Department of Public Utilities it will not meet the targets for finishing contract talks or contract filings for the latest round of the state’s offshore wind projects.
“The contracting parties have not yet completed their contract negotiations and are now targeting the completion of negotiations and execution of contracts with all three counterparties on or before Jan. 15, 2025. Accordingly, the evaluation team is now targeting the filing of contracts with the department on or before Feb. 25, 2025,” the letter said.
The latest delay means contracts almost certainly would be filed after Donald Trump returns to the White House.
The Public Service Commission has approved a rate increase for DTE Gas but is requiring the company to take steps toward reducing emissions and costs.Residential customers can expect about a $2 increase on their monthly bills. It is the second rate increase for DTE Gas in four years.Plans to reduce emissions and costs include incorporating the state’s emissions and electrification goals and planning for a decrease in the use of natural gas.
The Public Service Commission has announced it will open an investigation into the services provided by the Holly Springs Utility District.The city of Holly Springs has been summoned to appear before the commission on Jan. 7, 2025.The PSC said the decision follows months of complaints from the utility’s customers.
Balico Withdraws Application for Pittsylvania Power Plant, Data Center
Balico announced it was withdrawing its application to bring a power plant and data center to Pittsylvania County but said the project was not dead.The plans called for a 3,500-MW natural gas power plant to tap into the Mountain Valley Pipeline. The plant would have provided energy for a data center complex comprised of 84 two-story structures.
The Public Service Commission has approved rate increases for We Energies and Wisconsin Public Service.We Energies received an 8.79% increase over the next two years that will equate to a $7.62 increase in 2025 and a $9.73 increase in 2026.Wisconsin Public Service was approved for a 7.33% increase over two years. It will raise customers’ bills $7.11 in 2025 and $5.04 in 2026.
ALBANY, N.Y. — Celebration of a milestone achieved and concern about hurdles facing the next milestone were front and center as the New York Solar Energy Industries Association convened its annual Solar Summit.
New York reached 6 GW of distributed solar in October, 14 months ahead of the statutory target, thanks to supportive policies, public-private cooperation and more than $3 billion in state support.
There is concern, however, that the buildout effort is growing more difficult because of local restrictions, interconnection difficulty and regulatory delays.
NYSEIA represents 240 companies working in the rooftop and community solar sectors and advocates for changes that will help them reach the state’s next target — 10 GW of distributed solar by 2030.
How best to do this was a recurring theme at the Nov. 6-7 event.
It is a bright spot for a state that has struggled to bring larger-scale renewables online and expects to miss its statutory goal of 70% renewable electricity by 2030, perhaps by a wide margin. (See NY Expects to Miss 2030 Renewable Energy Target.)
New York is known as a slow and expensive place to develop generation and transmission but distributed solar with its smaller and more nimble profile has had an easier time than larger-scale solar and wind.
NYSEIA Executive Director Noah Ginsburg told NetZero Insider that extensive groundwork and policy support begun by the state several years ago allowed distributed solar to flourish, but the momentum is threatened.
“As we run into increasingly restrictive local laws, which really have proliferated across the state in the last couple years, and reduced hosting capacity on our electric distribution system, it’s a new set of challenges,” he said. “And the same kind of resolve and proactive approach that we had five years ago to create the conditions for our success, we need to do that again.”
A lot of the low-hanging fruit — the easy-to-develop sites — is gone, and there are other potential problems ahead. The summit was focused on state policies rather than federal, but the election of a president antagonistic toward climate protection and clean energy could not be ignored.
“It’s foundational,” Ginsburg said of federal financial support. “Projects don’t pencil without the investment tax credit.”
Americans support solar, he said, and its economic benefits transcend partisan boundaries.
“So I am hopeful that the federal government’s not going to pull out the rug from under the industry, but to me, what happened with the federal election just highlights the importance of state leadership.”
The agencies leading New York’s clean-energy transition were well-represented at the NYSEIA summit, including the Department of Public Service, Department of Environmental Conservation and New York State Energy Research and Development Authority.
NYSERDA Chief Program Officer Anthony Fiore delivered a keynote address highlighting the achievements to date and crediting the public-private partnership for making them possible.
“More than 1 million homes across New York state are being powered by renewable energy sources, and we’re seeing the impact of this on grid reliability,” he said. “This past summer, we saw an 8% decrease in peak demand because of behind-the-meter solar. That’s incredible!”
Panel discussions looked at ways to preserve the momentum.
What Works, What Needs Work
NYSEIA Board President Daniel Montante, co-founder of Montante Solar, boiled the wish list down to four key points: Siting reform; flexible interconnection and interconnection reform; rate design improvements; and targeted incentives for installations that provide tangential value, such as benefiting disadvantaged communities or repurposing brownfields.
That is a tall order, in New York or anywhere else. Montante tried to recruit the crowd at the summit into NYSEIA’s advocacy role in lawmaking and policy writing. “Getting policies like this in place is a big lift, but many hands make work light,” he said. “NYSEIA is the tip of the spear.”
Kelly Friend, vice president of policy at Nexamp, described a culture of support for solar within New York state government and a pattern of state agencies making challenges surmountable. “You had the sustained effort to maintain a long trajectory,” she said. “I think that we can probably contrast markets where it’s not working.”
However, she and other panelists said, there also are some things in the New York market that are not working.
Kevin Schulte, CEO of GreenSpark Solar, said business is mixed for his company — commercial/industrial is thriving but residential is struggling. “We’ve had to start looking at other markets for the first time in more than half a decade, to make sure that we can keep all of our people busy moving forward,” he said.
Finding overlap between grid hosting capacity and permissive local permitting is a challenge, he added.
Friend made the same point about local restrictions: “If we’re going to hit the next [state distributed solar] goal that we’re going to set, we can’t continue this paradigm of getting into regulatory dockets, burning a ton of cash to engage those.”
Schulte said greater transparency from utilities on things like the cost of a transformer or the load profile of a circuit would be very helpful in general and would be critical if there is to be an industry-utility partnership on things such as virtual power plants.
Matt Foran, National Grid’s vice president of account management, said there is some data the utility cannot share, but it will try to be more transparent.
“Starting with project cost data, the SIR reports, we’re endeavoring to share more of that, update our cost estimates more frequently, so that we are sharing that information more often than we have in the past,” he said. “We know it’s a pain point.”
Multiple speakers urged valuation of distributed energy resources such as solar and storage beyond their nameplate capacity and impact on the grid.
Friend said VDER, the Value of Distributed Energy Resources mechanism New York created in 2017, was revolutionary for its “value stack” treatment of an asset’s benefits to the grid.
“But let’s not think about the benefits just on the electric grid,” she said. “What are the public health benefits? What are the other benefits we get from not burning gas and not burning other fossil fuels? And how do we incentivize projects to show up and produce electricity without those externalities? And let’s bake that into the equation of how we incentivize these projects.”
Making Friends
New York has a strong home-rule tradition that complicates state government’s efforts to bring about change. There are more than 1,000 jurisdictions in the state and many different stances on renewable energy, ranging from support to skepticism to flat opposition.
The state in 2020 attempted an end-run around this by creating the Office of Renewable Energy Siting (ORES) and giving it power to override local rules on renewable proposals of 20 MW or larger under an obscure-sounding law called Section 94-c. And it did this through the famously opaque state budget negotiating process, during the COVID lockdown.
This was as unpopular with local governments as one might expect, and increasingly, their response has been to place moratoria and restrictions on wind, solar and storage development.
Ginsburg said NYSEIA estimates 4.6 GW of potential solar development is thwarted by local restrictions.
Matthew Eisenson, senior fellow at the Sabin Center for Climate Change Law at Columbia Law School, said a national report by the center found New York has one of the greatest concentrations of restrictive local laws. For a deeper dive, he recommended a Lawrence Berkeley National Laboratory report examining the motivations. (See Renewable Development Faces Regulatory Tangle.)
“There’s an irony here in that community solar generally attracts less opposition than utility-scale solar, but it’s more vulnerable to local restrictions,” Eisenson said.
Sarah Brancatella, deputy director of the Association of Towns, pushed back on the term “restrictive local laws” and on the image of local officials as obstructing the clean energy transition. There probably are some solar haters in local government, she said, but generally, local leaders are trying to do what’s best for their communities.
“Are they restrictive local laws, or are they just land-use laws? Are they just restrictive because we’re not letting developers do whatever the hell they want?” Brancatella asked.
“There’s a lot of sour feelings about 94-c,” she reminded the audience. “There can be a conflation between utility-scale solar and community solar, but the fact of the matter is that you guys are dealing with the reverberations from the way that 94-c was enacted.”
Ginsburg has wished aloud that ORES or something like it could expand its authority to include small renewable projects, and he asked a panel discussion about the idea. Brancatella said she and her membership would oppose that.
Brancatella also pushed back on the idea that local restrictions are as widespread as Eisenson suggested — there are 933 towns, and only about 9% have passed such laws per year since 94-c, she said.
Katie Soscia, executive director of development at Montante Solar, offered some pushback of her own: A map of towns with good interconnection potential and a map of towns that have restrictive laws would probably show considerably more than 9% overlap, she said.
Not coincidentally, areas with interconnection capacity draw the strongest interest from solar developers to the point that some consider saturation.
Jessica Waldorf, interim executive director of ORES, said the state is trying to ease this pressure by creating more opportunities for interconnection.
“One of the things that we can do better as a state, and that we are doing, is through our Coordinated Grid Planning Process and some of the other investments that the Public Service Commission has authorized to date, we’re looking at ways to expand the capacity of the transmission system, to open up new areas to development.”
Influencing People
Proactively expanding transmission capacity before it is needed has been a strategy the state is pursuing, but results are years away.
How to get a 5-MW solar array now stalled in review off the drawing board and into construction calls for a whole different set of strategies.
New York’s towns range from several hundred thousand residents to fewer than a hundred, from Hamptons glitz to Appalachian poverty. So there is no one-size-fits-all approach to developing solar power in them. Each project will be different.
There was no shortage of suggestions about what works and does not work from Brancatella, Eisenson, Ginsburg, Soscia, Waldorf, Tony DeFazio of Sustainable PR and David Sandbank, NYSERDA’s vice president of distributed energy resources.
These include:
Understand why a town has placed a setback restriction on solar panels — do they not want them nearby, not want them at all, or just not want to see them? Address those concerns.
Get feet on the ground for conversations to understand what locals want and do not want. Do this face-to-face — remote digital research is ineffective.
Win over the leaders and influencers in the community and use them as the hubs in a hub-and-spoke campaign to build wider support.
Do not talk down to communities about their need to contribute to the state’s climate goals.
Local officials like the idea of agrivoltaics and of preserving farmland for eventual reuse in farming rather than losing it forever to housing development.
Jobs are not an effective selling point as solar projects do not create many local jobs.
Ask the closest neighbors what they think — a visual screen around solar panels is all some people really want.
Explain the difference between community solar and utility-scale solar — early and repeatedly, without being pedantic.
Understand what benefits a particular host community is most interested in, then provide certainty and clarity about delivering those benefits.
Provide certainty and clarity about decommissioning a project, as well. The repeated sale and resale of a project from one company to another does not increase confidence that when it reaches the end of its service life, it will be removed as promised.
Making the Case
In the case of community solar, developers can win local approval only to find they still need to win more local support.
New York has high electric rates, and many New Yorkers have trouble paying their bills — as of September, the six investor-owned electric utilities reported nearly 1 million residential customers more than 60 days in arrears on a total of $1.52 billion in charges.
A key aspect of New York state’s support for distributed solar is directing its economic benefits to disadvantaged communities, those that could most benefit from lower power costs.
But it can be hard to recruit members of those communities as subscribers, said Jason Kaplan, chief legal officer of PowerMarket, which connects 92,000 customers to the 980 MW of community energy it manages.
“Definitely there have been challenges because we’re engaging with communities that, frankly, have been historically marginalized from renewable energy for a whole host of reasons, and there’s great skepticism when you go to the marginalized communities and say, ‘Hey, but guess what? I’ve got a product that’s gonna give you just guaranteed savings, and you don’t have to worry about anything else.’”
His solution to recruiting subscribers for community solar is similar to those offered earlier for winning approval to build the installations in the first place:
Enlist the support of trusted local voices to explain the benefits of community solar, then deliver those benefits.
And it has worked in New York, in places like Utica, Dunkirk and Clay.
“We’ve just seen an amazing success when it comes to those partnerships,” Kaplan said. “The town of Clay, we literally had like 800 residents. They were over-subscribing one of our projects, and we’re going to deliver that town’s residents over $130,000 in direct savings.”
This is the promise of distributed solar — collective benefit to the planet and pocketbooks that far exceeds its small individual pieces.
Helping deliver on that promise is the job of NYSEIA’s members, and while it is a business proposition for them, it also serves the larger picture of pushing New York closer to its climate and equity goals, even a few kilowatts at a time.
To cite the most extreme contrast, it can take more than a thousand of these small solar systems to equal the output of a single offshore wind turbine. However, there are nearly a quarter-million sites making up the 6 GW distributed solar total in New York, and just a dozen offshore turbines rated at a combined 132 MW.
There is room for both large and small, and a need for the unique strengths of both, Ginsburg told NetZero Insider.
When he calls for doubling New York’s next distributed solar target to 20 GW by 2035, he is not suggesting the state give up on large renewables but advocating for greater support for what has worked so far.
“The state of New York is projecting, what is it, a 45,000-GWh gap in renewable electricity supply by 2030,” he said. “As much as I have a lot of confidence in the people in this room, I don’t think they’re going to close that gap on their own.”
He added: “I think we really do need a diversified clean energy mix. It’s true that one wind turbine can generate as much power as a thousand residential solar projects. It’s also true that we can build a thousand residential solar projects in a good month, and it takes years to get permits for the large-scale projects.
“To me, the message is we need to be building all these resources, and let’s do it in a smart way.”
Public Service Company of New Mexico announced Nov. 11 its intent to join CAISO’s Extended Day-Ahead Market, extending EDAM’s reach farther into the Desert Southwest in its latest victory over SPP’s Markets+.
In a statement, PNM CEO Don Tarry cited the utility’s experience with CAISO’s Western Energy Imbalance Market (WEIM) as a factor in the decision. PNM has received $125 million in benefits since joining WEIM in 2021.
“Participating in EDAM is the next step in realizing the value of New Mexico’s renewable energy potential for our customers, helping us ensure continued clean and reliable service at the lowest possible cost,” Tarry said. “We know from our experience with the WEIM … [that] coordination with other regional utilities can continue to deliver substantial efficiencies and cost benefits for our customers.”
With about 550,000 customers, PNM is New Mexico’s largest electricity provider. The utility said it plans to begin EDAM participation as soon as 2027.
CAISO CEO Elliot Mainzer said the ISO was pleased by PNM’s announcement.
“We look forward to building on the proven track record of the Western Energy Imbalance Market to deliver even greater economic and reliability benefits to PNM customers,” Mainzer said in a statement.
Modeling Connectivity
Playing a large role in PNM’s choice of EDAM was a study The Brattle Group conducted for PNM and El Paso Electric that compared projected benefits of the utilities joining either EDAM or Markets+.
The production cost study carefully modeled transmission connectivity. It modeled a scenario in which three Arizona utilities — Arizona Public Service, Salt River Project and Tucson Electric Power — join Markets+. The Arizona utilities haven’t yet announced their day-ahead market choices, but they have expressed a preference for SPP’s market and have participated in its development.
The Brattle results gave reassurance that PNM didn’t have to follow the market choice of Arizona utilities in order to realize day-ahead market benefits.
“The Brattle study reinforced that PNM has adequate transmission connectivity to reach the benefits associated with the large and resource-diverse EDAM market,” the company said in an email to RTO Insider.
At the same time, PNM didn’t have any major concerns with the Markets+ design, the company said, adding that the EDAM choice was based on customer benefits from a reliability and economic perspective.
“Much of these benefits come from having diverse loads and resources spread over a large geography,” PNM said.
Guiding Principles
PNM filed a letter with the New Mexico Public Regulation Commission on Nov. 8 sharing its decision to go with EDAM. The brief letter references a set of guiding principles the commission issued Oct. 31 for utilities to consider in selecting a day-ahead market. (See NM PRC Issues ‘Guiding Principles’ for Electricity Market Participation.)
PNM said it made its day-ahead market decision after considering the commission’s principles, “including the comparative analysis of customer benefits, the efficiency of resource dispatch and the importance of robust stakeholder processes.”
The utility plans to file a more detailed response on how EDAM satisfies the PRC’s guiding principles before signing implementation agreements with CAISO, the company said in an email.
PacifiCorp in April became the first Western utility to fully commit to EDAM and sign an implementation agreement with CAISO. That was followed by NV Energy’s announcement in May that it plans to join EDAM.
The Balancing Authority of Northern California, Idaho Power, Los Angeles Department of Water and Power, and Portland General Electric also have made commitments to EDAM.
As for El Paso Electric, which participated in the Brattle study with PNM, the utility has said it hopes to make a day-ahead market decision by the third quarter of 2025. The study’s projected benefits for EPE are $19.1 million a year for EDAM, versus $9.1 million for Markets+.
The company may ask Brattle for analysis of additional scenarios, which could include EPE and PNM choosing different markets. EPE is expected to present the results of those studies to the PRC.
Tensions flared at the NYISO Installed Capacity Working Group meeting Nov. 4 over the ISO’s proposed changes to the special case resource (SCR) demand response program, which large energy consumers said will cause a mass exodus of participants.
“I think NYISO should know that part of the extreme frustration with this project is that we thought there was going to be actual engagement with the demand side; that there would be engagement with SCR participants,” said Mike Mager, speaking for Multiple Intervenors, a group of large industrial customers.
Mager said that he believed the vast majority of the changes proposed to the SCRs would be viewed unfavorably by the participants.
SCRs typically are large industrial consumers that have loads that can be reduced or turned off. In a report to FERC, NYISO said that from November 2023 to April 2024, the SCR market reduced load by about 1,300 MW statewide. Local behind-the-meter generators participating in the SCR program contributed an additional 100 MW. NYISO allows customers who qualify to participate in the Installed Capacity Market to be SCRs, receiving revenue for reducing their load at the ISO’s direction.
The ISO proposes to change how SCR performance and compensation are calculated. Currently they are based on the average coincident load (ACL), which is the average of the SCR’s highest 20 one-hour peak loads from the previous capability year. NYISO wants to change this to the “customer baseline load” (CBL), which uses data from the prior 30 calendar days and is based on the highest five consumption days of the past 10 prior to an SCR event.
NYISO’s market design report from 2023 estimated this would reduce the megawatt value of an SCR by 6% to 26% depending on the zone; in New York City, this would be about 26%. Michael Ferrari, a market design specialist for NYISO, said the changes more accurately would capture the performance of SCRs.
“The whole ACL/CBL change was not part of any type of engagement,” Mager said. “The testing proposal we’re going to get to is also new by the NYISO. The four-hour notices was also new by the NYISO. There was some discussion about the notice period during the engagement phase, but the feedback provided by the SCR participants was largely ignored.”
NYISO also wants to increase the duration of the performance test of an SCR to six hours, up from one. In prior meetings ISO staff also expressed a desire to increase the duration requirement of an SCR to six hours and shorten the notice window from 21 hours to four hours. (See Large Consumers Miffed at NYISO Proposal to Shorten SCR Notice Period.)
“This deal just kind of seems to be getting worse and worse,” said Aaron Breidenbaugh, senior director of regulatory and government affairs for CPower. “For a project that’s supposed to be coming out of ‘Engaging the Demand Side,’ I think a word besides ‘engaging’ is more appropriate.”
Mager said the changes were moving in the wrong direction, disincentivizing participation at a time when the state’s reliance on intermittent generation was increasing. Shutting down manufacturing for longer SCR testing, or on shorter notice for less compensation, was an overall bad deal for manufacturers, he said.
“The last time we talked about this, I used the Titanic analogy,” said Breidenbaugh. “Now we’ve just punched a hole in two more compartments.”
Breidenbaugh said if he was working at NYISO and had been given the job of eliminating the SCR program, he would do exactly what the ISO was proposing to do.
“If you’re trying to get rid of it, you’re doing a really good job, but I don’t think that’s what you’re trying to do,” he said. “I think everyone can believe that this could make a better program with more flexible megawatts. You’ll have more flexible resources; they will just be a tiny fraction of what you have.”
“I’ve not been given the request to kill the SCR program. That is not the intent of this series of proposals,” Ferrari said.
After some additional discussion, Breidenbaugh said he didn’t think New York state’s regulatory authorities would allow the amount of DR that is dependent on participating in the SCR program to go away. He said if the changes caused participants to jettison from the program, the state might work with utilities to get its own program in place.
“I certainly don’t think it’s the best way for NYISO and its operators to lose control of those levers,” he said. “I’m not sure the utilities necessarily want to take on that responsibility, but they oftentimes get tasked with doing things they don’t want to do.”
FERC on Nov. 8 approved a PJM waiver request to offset the RTO’s capacity auction schedule by six months starting with the 2026/27 Base Residual Auction (BRA).
The order shifts the 2026/27 auction from December 2024 to June 2025 and schedules the three subsequent three auctions for December 2025, May 2026 and December 2026. It also cancels the second Incremental Auction (IA) for the 2027/28 delivery year and first IA for the 2029/30 delivery year.
The commission said the delay would allow PJM to address a complaint filed by several environmental and public interest organizations regarding how generators operating on reliability must-run (RMR) agreements are reflected in PJM’s capacity market.
Filed by the Sierra Club, NRDC, Public Citizen, Sustainable FERC Project and Union of Concerned Scientists, the complaint argues those units should be required to offer into the capacity market or should be administratively counted in the supply stack by PJM. They contend the status quo requires consumers to pay repeatedly for the same reliability contribution in the form of the RMR agreement, transmission upgrades to mitigate violations caused by the generator’s deactivation, and higher capacity prices when a unit leaves the market to operate on the RMR agreement (EL24-148).
“PJM explains that the complaint has generated significant market uncertainty and that, to address this uncertainty, it plans to file a FPA Section 205 filing that will propose several capacity market rule changes. PJM’s waiver will provide the time to address potential consequential changes in the market rules by delaying the 2026/2027 BRA and compressing the timelines for subsequent auctions to facilitate the return to a three-year forward schedule,” the order states.
Insight into Upcoming Filing
PJM presented an overview of its expected filing during a Nov. 7 special Markets and Reliability Committee meeting, in which Vice President of Market Design and Economics Adam Keech said the filing likely will include changing the reference resource back to a combustion turbine (CT) and setting criteria for counting the expected output of the Brandon Shores and Wagner units operating on RMR agreements toward meeting RTO and locational deliverability area (LDA) reliability requirements.
The change would include sunset provisions with the aim of being applicable to only those two units while broader changes to the RMR rules are worked out through the stakeholder process.
Those stipulations mandate that units be reasonably expected to operate throughout the delivery year, have a minimum number of available run hours to be available for transmission support, be available to PJM for all emergencies unless on outage and have deliverable capacity interconnection rights (CIRs).
Keech said PJM has determined that Wagner Unit 3 meets those requirements and it is working to determine whether Unit 4 would as well. Due to an agreement between the Sierra Club and Talen Energy to cease coal combustion at Brandon Shores by the end of 2025, it is not clear that generator could be relied upon.
While not addressed in the complaint regarding RMR resources, PJM also seeks to revert the reference resource to a CT, undoing a change made in the 2022 Quadrennial Review to shift to a combined cycle generator. Due to the higher energy and ancillary service (EAS) revenues, the net cost of new entry (CONE) value fell to $0/MWh in some LDAs, resulting in a capacity performance penalty rate of zero as well. That could occur in situations where generators face no non-performance charges during emergencies but still could receive overperformance bonuses. The diminished net CONE values also produce a significantly steeper variable resource rate (VRR) curve, creating price volatility in the capacity market.
The commission’s order says the harms of changing the auction schedule are outweighed by the benefits of addressing the possible consequences of the market rules and allowing market participants to react to any rule changes.
“Although the auction delay will have an effect on other BRAs through the 2029/2030 delivery year and will require canceling several Incremental Auctions, on balance we find that granting the waiver request provides the opportunity to address potential consequential changes in the market rules and provides the opportunity for market participants to respond to any changed rules by having additional time to prepare and submit requests and elections in advance of the next auction,” the order says.
FERC disagreed with American Municipal Power’s protest arguing that the waiver request was deficient without a stronger outline of what would be included in the 205 filing, countering that it is reasonable to request a delay to allow for consideration of changes still being drafted.
The commission dismissed as moot a parallel request to delay the auction that PJM made in its comments on the RMR complaint, saying the approval of the waiver request does not prejudice its consideration of that complaint.
Stakeholders Endorse LS Power Issue Charge on CETL
PJM’s Planning Committee voted by acclamation to endorse an issue charge from LS Power to examine a “disconnect” between risk modeling that has shifted loss of load risk from summer peaks to the winter and the calculation of zonal capacity emergency transfer limits (CETLs), which continues to be based on summer peaks.
The issue charge argues that the CETL calculation continues to focus on summer risk in a holdover from the capacity accreditation model in place before FERC approved PJM’s shift in accreditation and risk modeling in January. The difference could lead to incorrect capacity prices between locational deliverability areas (LDAs), the company wrote. (See FERC Approves 1st PJM Proposal out of CIFP.)
The issue charge considers as out of scope any changes to accreditation outside of the marginal effective load carrying capability (ELCC) accreditation model and consideration of a sub-annual capacity market.
The issue charge is one in a series of changes to the capacity market LS Power is seeking to make in the first quarter of 2025. The Markets and Reliability Committee (MRC) also endorsed two issue charges focused on the transparency and functionality of PJM’s marginal ELCC paradigm, which was also implemented through PJM’s critical issues fast path (CIFP) filing approved in January. (See “Stakeholders Endorse Issue Charges on ELCC,” PJM MRC Briefs: Oct. 30, 2024.)
PJM Floats Fast Track Proposal on Site Control Modifications for Queue Projects
PJM’s Jonathan Thompson presented a fast track proposal to add more detail to Manual 14H: New Service Requests Cycle Process around how developers can modify their site control requirements for projects in the interconnection queue. The fast track process allows for an issue charge to be voted on concurrent with a proposal.
At Decision Point 1, the footprint of a project can be reduced so long as it continues to meet the minimum acreage and energy output listed in the application. The land requirements are scaled down if the project output is correspondingly reduced. Additional parcels can be added to a project as long as they are adjacent to the land included in the application. If they do not abut the original outline, then easements must be provided showing how the additions will be connected to the project.
Parcels can continue to be removed from a project at Decision Point 2, and land can be added similarly to Decision Point 1. No additions are permitted at Decision Point 3; however, reductions in size can be submitted.
The revisions would also rework Exhibit 10 in the manual, which is meant to detail how a generator interconnects to existing transmission substations but incorrectly uses a diagram from a different exhibit.
Transmission Expansion Advisory Committee
PJM Presents Shortlist of Projects for 2024 RTEP Window 1
Eight packages of projects have been shortlisted to expand west-to-east power flows across the PJM region under the first window of the 2024 Regional Transmission Expansion Plan (RTEP). The need is largely driven by data center load growth in Dominion drawing increasing power from the west, which is expected to see growth in generation.
Developers submitted 88 individual projects, along with six joint proposals packaging multiple components together. All the proposals would include expanding west-to-east flows by expanding the 765-kV network, either through a Joshua Falls to Axton-Morrisville corridor or a corridor from the John Amos substation to northern Virginia.
The 765-kV upgrades Dominion, FirstEnergy and Transource jointly proposed to develop to the south of the Dominion region would offer higher initial transfer capability, while upgrades to the north would have greater possible transfers once complete. Variants of the northern reinforcements were proposed by LS Power, NextEra and a joint Transource, FirstEnergy and Dominion package.
The projects will be ranked on their effectiveness in meeting system needs in 2029 and providing long-lead reinforcement for 2032, as well as on how they maximize use of existing rights of way, cost evaluation and containment provisions, development experience and operating 765-kV assets and scalability to address future load growth.
PJM Director of Transmission Planning Sami Abdulsalam said there has been a significant intake in load growth since the RTEP project submission window was opened, leading the RTO to widen the lens it views projects through to include needs being identified in the upcoming 2025 load forecast.
Several stakeholders objected to PJM including an unreleased load forecast in its consideration of the projects, arguing that doing so would be unfair to transmission developers who were unable to include that data when designing their submissions. It could also provide an advantage to incumbent transmission owners, who would have insights into load growth that is not yet public and could design their project submissions to address both the inputs available when the RTEP window opened and future load forecast being supplied to PJM.
Virginia ratepayers also spoke against the possible impacts the projects could have on residents along the proposed corridors, saying that routes could require eminent domain of homes and arguing that PJM is misclassifying expansions of right of way as upgrades rather than greenfield development. Abdulsalam responded to the latter point saying PJM is trying to avoid having several different definitions of greenfield, brownfield and upgrades.
Supplemental Projects
AEP presented a $169.1 million project to serve a data center customer in New Haven, Ind., with an initial load of 480 MW coming online in November 2026, which is set to grow to 1,200 MW by July 2029. The project is in the scoping phase with a projected in-service date of July 1, 2029.
The load would be served by five 138-kV double circuit lines to customer-owned substations, which would be fed by a new Zodiac 138-kV substation in a breaker-and-a-half configuration. Zodiac would be cut into the Allen-Lincoln double circuit 138-kV line, and the Allen- Wayne Trace and Allen-Magley 138-kV lines. Two additional 345/138-kV transformers would be installed at the Allen substation, along with three additional 138-kV breakers and three 345-kV breakers.
PPL presented a $117.8 million project to serve a 138-kV customer in Lancaster, Pa., increasing its load by 350 MW in 2028. The project is in the conceptual phase with a projected in-service date of June 1, 2028.
A new 138-kV switchyard, to be named Pitney, would be constructed in a breaker-and-a-half configuration with five 138-kV breakers to feed into the customer substation. The facility would cut into the South Akron-Prince 138-kV line with 0.2 miles of new line.
A second new 230/138-kV substation, named Lampeter, would be built with two transformers and two breakers for each voltage. The facility would be cut into the Millwood-South Akron 230-kV line and the 69-kV double circuit tap line terminating at the Strasburg substation would be reconstructed to 138-kV to loop into Lampeter and terminate at Pitney. Both the Greenland and Strasburg substations would be upgraded from 69/12-kV to 138/12-kV.
An additional load increase in Lancaster to serve an additional 350 MW of load at the same customer substation by 2029 would be served by a $67.5 million project to build a new 138-kV switchyard named North Lancaster. The project is in the conceptual phase with a projected in-service date of June 1, 2028.
The facility would cut into the West Hempfield-Prince and South Akron-Dillerville 138-kV lines and serve the load with three 138-kV lines running 0.1 miles. Around eight miles of the West Hempfield-Prince line would need to be rebuilt as part of the project.
PPL presented a third project to serve a new customer in Hazleton with an initial load of 250 MW in 2027 growing to 1,000 MW by 2030. The $73.3 million project is in the conceptual phase with a projected in-service date of May 30, 2028.
The customer would be fed by a new 230-kV breaker and a half switchyard named Slykerville, which would be equipped with a 125-MVAR capacitor bank. The Harwood-Tresckow 230-kV line would be looped into the Slykerville facility with 0.2 miles of new line.
Around 2.7 miles of the Susquehanna T10-Susquehanna 230-kV lines would be reconductored and 15-ohm series reactors installed at the Susquehanna switchyard on the 230-kV line to Harwood.
Dominion presented a $13 million project to construct a new 230-kV substation, named Towerview, to serve a new customer in Fairfax County, Va., with an initial load of 56 MW in 2027 growing to 300 MW in 2029. The new facility would be cut into the Reston-Park Center 230-kV line. The project is in the engineering phase with a projected in-service date of Nov. 30, 2027.
FirstEnergy presented a $15.4 million project in the JCPL zone to address a possible load drop under N-1-1 contingency on the Gilbert-Martins Creek 230-kV and Gilbert-Pequest River 115-kV lines and replace a 115/34.5-kV transformer at the Morris Park substation. The project is in the conceptual phase with a projected in-service date of Jan. 29, 2027.
The project would reconfigure the Morris Park 230-kV substation into a four-breaker ring bus and cut the facility into the Martins Creek-Gilbert line. A second 230/34.5-kV transformer would be installed at Morris Park and all 115-kV equipment, including the 115/34.5-kV transformer, would be removed.
The utility also presented a $16.3 million project in the Met-Ed zone to mitigate a stuck breaker and fault contingencies at the North Hershey substation. The project is in the conceptual phase with a projected in-service date on Dec. 17, 2027.
The project would convert the 69-kV bus into a four-breaker ring bus and install a second 230/69-kV transformer, one 230-kV circuit breaker, four 69-kV breakers and associated breaker equipment.
