The Biden administration on Nov. 12 rolled out a new plan to triple nuclear power in the U.S. by 2050, with a multipronged strategy of building new large and small modular reactors, adding power to and extending the life of existing plants, and bringing recently closed installations back online.
The U.S. has 94 reactors in operation at 54 sites in 28 states, most of them built in the 1970s and 1980s, the plan says. But the Department of Energy estimates the country will need 200 GW of new nuclear capacity “to keep pace with future power demands and reach net-zero emissions by 2050,” according to a Nov. 12 blog accompanying the release of the report.
The White House wants to jumpstart a “nuclear deployment ecosystem” by getting 35 GW of new nuclear power online or under construction by 2035 and then build to a steady pace of deploying 15 GW per year in the U.S. and globally by 2040 ― targets the report calls “ambitious yet achievable.”
For example, the report notes that “uprating” existing plants ― increasing their capacity through plant upgrades and the use of advanced fuels ― could increase their power output by 10% to 20%. Other DOE research suggests building new reactors at existing plants could add 60 GW or more of new capacity.
DOE also supports the development of SMRs through its Advanced Nuclear Reactor Demonstration Program, which received $2.5 billion in the Infrastructure Investment and Jobs Act. The department’s Loan Programs Office in September announced a $1.52 billion loan to Holtec to support the reopening of the 800-MW Palisades nuclear plant in Michigan.
Nuclear currently provides about 20% of all U.S. power and close to half of its carbon-free electricity, and interest in the clean, 24/7 power that reactors produce has intensified as companies like Microsoft, Google and Amazon look for power for their hyperscale data centers.
The report notes that “a diverse set of technologies” will be needed to meet the different needs of customers and calls for “customers with large power needs and carbon-free commitments to work creatively with utilities to help share project risks commensurate with resulting benefits of successful deployment.”
The Need for Standardization
The report also makes an argument for nuclear expansion as critical for national security.
The majority of new reactors built worldwide in the past decade have been either Russian or Chinese, the report says. “It is imperative that the United States and allied countries compete effectively to supply the world with clean and safe nuclear energy. Yet, countries abroad typically want new reactor technologies demonstrated in the supplier country before building them in their own country.
“Domestic deployments will enable exports and provide a pathway for the United States to regain leadership in the international nuclear energy market and supply chain.”
According to DOE, a majority of existing U.S. nuclear power plants could add up to 60 GW of new capacity with large-scale light water reactors. | DOE
A major challenge moving forward, for both large-scale and SMRs, will be overcoming investor and utility concerns about time and cost overruns, with the report calling for better standardization of reactor designs.
The existing U.S. nuclear fleet did not move down the cost and time curves “in large part because most plants were built with unique, bespoke designs,” the report says. “The 94 currently operating reactors in America represent over 50 different combinations of reactor types, nuclear steam supply systems, models, power levels, containment types and balance-of-plant architecture.”
The next generation of reactors “must feature greater standardization, along with integration of modern design, project management and construction techniques, and a wealth of lessons learned from past deployments,” the report says.
Out but not Down
Any plans by the Biden administration would appear to be moot given the incoming Republican administration, but nuclear energy is one of the rare points of bipartisan agreement, as exemplified by the passage of the Accelerating Deployment of Versatile, Advanced Nuclear for Clean Energy Act of 2024 (S. 870), signed by President Joe Biden in July.
The law aims to accelerate the licensing of new reactors with provisions that reduce licensing fees for SMRs and require the Nuclear Regulatory Commission to streamline licensing for microreactors and cut the timelines for licensing new reactors planned for existing plant sites.
The report lists 30 actions the U.S. government can take “within existing statutory authorities,” along with recommendations for industry and customers. The NRC has issued its own License Renewal Roadmap to streamline reactor relicensing, but the report encourages plant owners to coordinate with the commission on the timing of their relicensing applications “to produce a more consistent workload for NRC … and ensure resources are in place and priorities are shifted as necessary.”
The administration also is following through on a U.S. commitment to the Declaration to Triple Nuclear Energy made by more than 20 countries in 2023 at the 28th U.N. Climate Change Conference of the Parties (COP28) in the United Arab Emirates.
Speaking at COP29 in Azerbaijan on Nov. 11, White House Senior Adviser John Podesta acknowledged that President-elect Donald Trump would pull the U.S. out of the Paris Agreement again, but that would not stop states, cities and businesses from continuing their commitments to cut emissions to limit global warming to 1.5 degrees Celsius.
“The economics of the clean energy transition have simply taken over,” Podesta said in a White House release. “New power generation is going to be clean. The desire to build out next generation nuclear is still there. … The hyperscalers are still committed to powering the future with clean energy, including safe, reliable nuclear energy. … All those trends are not going to be reversed.”
Trade associations sought to focus on the economic and bipartisan appeal of nuclear in their reactions to the report.
“Nuclear generation is uniquely positioned to help the United States achieve our climate and national security goals, while creating a reliable energy system to meet growing demand,” said Maria Korsnick, CEO of the Nuclear Energy Institute. “We look forward to continuing to advance strategies that extend the lives of existing nuclear reactors, usher in a new era of advanced technologies and support a global marketplace for U.S. exports.”
While welcoming the report’s aggressive targets, Judi Greenwald, executive director of the Nuclear Innovation Alliance, said the “next steps are up to the incoming administration and Congress. We look forward to continuing bipartisan and public-private cooperation to build on our shared accomplishments and increase investment and innovation in the next generation of advanced nuclear energy.”
NERC Vice President of Engineering and Standards Soo Jin Kim on Nov. 12 said the ERO’s ongoing cold weather standards project could supply the next opportunity for the Board of Trustees to exercise its authority to streamline the normal stakeholder approval process.
Speaking at a technical conference about Project 2024-03 (Revisions to EOP-012-2), Kim acknowledged “there’s a little bit of industry fatigue” around the effort. She was referring to the fact the cold weather standard is undergoing its second set of revisions after FERC approved the original version, EOP-012-1 (Extreme cold weather preparedness and operations), in 2023 and its successor, EOP-012-2, this year but ordered changes each time. (See FERC Orders Further Cold Weather Standard Modifications.)
The deadline for the FERC-ordered revisions to EOP-012-2 is next March, but the replacement standard EOP-012-3 recently failed to gain industry approval in its first formal ballot period that concluded Nov. 5. The standard received 70 supportive votes from industry stakeholders but 129 negative votes with comments; 55 respondents either abstained or did not vote. The result was a segment-weighted 42.29% in favor of passage, well short of the two-thirds majority needed to put it before the board.
A similar situation caused the board to invoke for the first time its authority under Section 321 of NERC’s Rules of Procedure at its last open meeting in August. On that occasion, the failure of PRC-029-1 to receive industry approval led the board to direct the Standards Committee to host a technical conference in September to hear industry feedback on the proposed standard. Convening a tech conference is among the options in the section available to the board if stakeholders do not pass a proposed standard directed by FERC or NERC.
In the case of PRC-029-1, FERC had ordered NERC to develop standards governing inverter-based resources. (See “Board Invokes Standards Authority to Meet IBR Deadline,” NERC Board of Trustees/MRC Briefs: Aug. 15, 2024.) Following the conference, NERC used the input to revise the standard, and it subsequently passed a final ballot, which was submitted to FERC along with four other standards governing IBRs.
Following the success of the new process, NERC indicated it might convene technical conferences for other projects that have faced difficult ballot processes, in hopes of proactively addressing stakeholder concerns. At this week’s conference, Kim said additional action — including another use of the Section 321 powers — has not been ruled out.
“I have gotten a lot of questions with regard to [whether] this project [would] be a candidate for 321 action,” Kim said. “The answer is ‘yes.’ We do feel this risk is very critical, and this is one of those projects where, if we are at an impasse … would be a candidate for 321 recommendations.”
Kim emphasized that NERC’s board has not made any decision about whether to invoke the Section 321 authority at this point and will “probably” not discuss the issue at its open meeting in December; the standard’s “next ballot will be the determining factor,” she added.
She explained she wanted to be “very transparent” about the possibility of special action after NERC received feedback from industry that the ERO had not been forthcoming about its consideration of using Section 321 for the IBR standards.
“I don’t want anyone to ever come back and say that we were not very upfront about whether or not this is a potential risk for us moving forward,” Kim said. “We are very concerned [about] making sure that industry is able to mitigate these risks with regard to certain timelines.”
The U.S. Bureau of Ocean Energy Management (BOEM) issued the final environmental impact statement (FEIS) for SouthCoast Wind on Nov. 8, bringing the project one step closer to final approval.
The project’s construction and operations plan would allow for the development of up to 2,400 MW of power on a 127,388-acre lease area south of Massachusetts. Rhode Island and Massachusetts recently selected 1,287 MW of power from the project’s first phase of development in a coordinated solicitation. (See Multistate Offshore Wind Solicitation Lands 2,878 MW for Mass., RI.)
SouthCoast Wind developer Ocean Winds, owned by EDP Renewables and ENGIE, predicts that SouthCoast Wind 1 will come online by 2030. It recently received several key state environmental approvals from Massachusetts, where the project will interconnect to the grid.
“Completing this environmental review represents another major milestone in the [Biden] administration’s commitment to achieving clean energy objectives that will benefit local communities,” said BOEM Director Elizabeth Klein.
BOEM plans to publish the notice of availability of the FEIS in the Federal Register on Nov. 15. That will be followed by a 30-day waiting period before the agency can issue a final record of decision.
The agency considered how the project proposal and several alternatives would affect local communities and the environment, qualitatively evaluating benefits and adverse impacts. BOEM conducted isolated impact analyses of the project alternatives as well as cumulative impact analyses, which evaluate project impacts within the context of outside stressors including climate change and other planned offshore wind projects.
Regarding ecosystem and wildlife effects, the report found the proposal would have minor adverse impacts on local birds, bats and sea turtles, and moderate adverse impacts on benthic resources, coastal habitat and fauna, fish habitat, marine mammals and wetlands.
The statement noted that the habitat of several endangered species of whale, including the critically endangered North American right whale, overlaps with the project area.
To limit harms to marine mammals, BOEM identified a preferred project alternative that would remove six wind turbine generators (WTGs) from a part of the lease area adjacent to the Nantucket Shoals, which it wrote is “an area of high biological productivity.”
“The removal of six WTGs in the northeastern edge of the lease area would reduce potential noise disturbance in turbine positions closest to Nantucket Shoals, thus decreasing associated risks to marine mammals, especially [North American right whales], that are known to use this area,” BOEM wrote, adding that the alternative similarly would reduce risks from vehicles in this area.
BOEM found the preferred alternative would have a moderate adverse impact on whales, but noted the possibility of major adverse impacts on right whales due to the species’ small remaining population and the disproportionate impact a single death could have on the species’ viability.
The agency found the proposal would lead to major cumulative impacts on the fishing industry, writing that “some fishing operations could experience long-term, major disruptions.”
The proposal also would affect cultural resources and scenic resources and could have a disproportionate impact on Tribal Nations, BOEM said. The project’s construction also could cause an increase in local air and noise pollution, coastal land use challenges, increased vessel traffic and conflicts with the tourism industry, BOEM found.
The no-build alternative — which accounts for the effects of climate change and the development of other offshore wind projects — also demonstrated many similar adverse effects, BOEM noted.
For benefits, the agency found the project would bring employment opportunities and tax revenue associated with the offshore wind industry, port infrastructure improvements, and emissions and climate benefits for displaced fossil generation.
Offshore wind industry representatives applauded the release of the FEIS, which came at the end of a turbulent week for offshore wind companies in the wake of the U.S. election.
“With its final approval later this year, the U.S. market will have 11 commercial-scale projects either completed, under development, or ready to break ground, representing more American jobs and tens of billions of dollars in economic activity,” said Liz Burdock, CEO of the Oceantic Network.
Burdock gave a nod to the first Trump administration for issuing SouthCoast Wind’s lease and emphasized the project’s potential economic and employment benefits.
Trump took aim at the offshore wind industry in the leadup to the election, but offshore wind leaders hope the industry has enough momentum and support to survive Trump’s second term in office. (See Clean Energy Sectors Brace for Impact of Trump 2.0.)
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.
Colette 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.
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.
