RTO Insider

March 17, 2025

EPA Puts Hold on Atlantic Shores OSW Permit

After receiving final approval in October 2024, Atlantic Shores, New Jersey’s sole remaining offshore wind project, has suffered a new setback and is on hold pending an EPA review and reevaluation of federal offshore wind leasing and permitting practices.

On March 14, EPA’s Environmental Appeals Board granted the agency’s motion for a “voluntary remand” on the air quality permit for the project, essentially returning it to EPA for re-evaluation in light of President Donald Trump’s Jan. 20 executive order on offshore wind.

The order withdrew all areas in the U.S. Outer Continental Shelf from offshore wind leasing and ordered a “temporary cessation and review of federal leasing and permitting practices.” However, the order states that “nothing in this withdrawal affects rights under existing leases in the withdrawn areas. With respect to such existing leases, the secretary of the Interior, in consultation with the attorney general as needed, shall conduct a comprehensive review of the ecological, economic and environmental necessity of terminating or amending any existing wind energy leases.”

EPA’s motion for remand claims Atlantic Shores had not received a final permit and therefore was subject to review and re-evaluation.

In its rebuttal to EPA’s motion, Atlantic Shores argued the voluntary remand should not be granted solely on the basis of Trump’s broadly worded executive order. The project had, in fact, received a final permit, and the agency “has not provided good cause for its motion, failing to identify any permit condition it seeks to substantively change or any element of the permit decision it wishes to reconsider,” the rebuttal said.

EPA also has not identified any provisions of the Clean Air Act or OCS air permitting regulations “that would justify a remand,” Atlantic Shores said.

However, the board’s panel of three judges rejected Atlantic Shores’ argument, saying EPA need not cite specific provisions in a permit it wants to review.

“The board treats requests for voluntary remand liberally and is not limited to circumstances where [EPA] provides specific substantive changes to the final permit or specific elements of the permit decision it seeks to reconsider. …

“The board has generally exercised its broad discretion to grant a permit issuer’s voluntary remand request where the permitting authority is reevaluating its permit decision, because in this situation ‘it would be highly inefficient for the board to issue a final ruling on a permit.’”

The ruling also stated that the board would not accept any appeals of the final permit decision resulting from the remand.

EDF Renewables North America, the developer behind Atlantic Shores, has said it remains committed to the project.

“In a time where the demand for electricity is surging, it is imperative that all forms of power production contribute to deliver all-of-the-above solutions,” said Ryan Pfaff, executive vice president for grid-scale power at EDF. “The Atlantic Shores offshore wind project stands as a frontrunner in advanced energy initiatives, poised to supply substantial megawatt-hours to the grid and bolster American energy dominance,”

“Unfortunately, the recent EPA decision has resulted in a significant setback, erasing years of progress and investment in a complex permitting process,” Pfaff said in an email to NetZero Insider.

EPA has yet to provide details on its process for reviewing and reevaluating the Atlantic Shores permit, whether the process will include opportunities for public and stakeholder input and how long the review might take.

State Support Lags

Atlantic Shores has faced multiple challenges over the past decade. The original federal auction for the Atlantic Shores lease sites was held Nov. 9, 2015, and the sale agreement was finalized in March 2016, according to the Bureau of Ocean Energy Management’s web pages on the project.

The project actually includes two lease sites, Atlantic Shores 1 and 2, to include 197 locations where turbines, undersea substations and a meteorological tower would be built. At its closest point, the project would be 8.7 miles from the New Jersey coastline.

Atlantic Shores 1 was approved by the New Jersey Board of Public Utilities for 1,510 WM. The capacity for the second project still is being determined, but BOEM said the two projects together could provide 2,800 MW.

Transmission lines for the project would come ashore in Atlantic City and Sea Girt, N.J. Local opposition to Atlantic Shores has been ongoing since it was announced, with concerns raised by the fishing and tourism industries and shoreline communities concerned about the project’s impact on “viewsheds” and local economies.

BOEM issued its notice of intent to conduct an environmental review of the project in September 2021. The draft environmental impact statement was issued in May 2023, followed by a series of in-person and virtual public hearings. The final EIS was issued in May 2024, and the permit for construction and operation in October. (See BOEM Approves NJ’s Atlantic Shores OSW Project.)

The 560-page FEIS found that the project would impact the commercial and recreational fishing sector through a range of activities, including anchoring, cable emplacement, noise, port use and structure presence. Beyond its closest point, the project would be about 10 miles offshore.

But the FEIS also concludes the area would suffer major environmental impacts even if the project were not built. Those impacts would stem from factors including fishery management measures taken to ensure the volume of fish caught is sustainable; the impact of climate change from ocean warming, sea level rise and ocean acidification; and non-OSW construction on land. 

Likewise, the study found that though the project would have a major scenic impact on the area — on the open ocean, seascape, and landscape character and views — the coast would suffer strong scenic impacts regardless due to onshore development and construction activities, offshore vessel traffic and the effects of other OSW projects. 

However, market conditions and uncertainty have presented steeper challenges. In January, Atlantic Shores lost a key partner when Shell New Energies U.S. withdrew from the project. (See Shell Quits Atlantic Shores Offshore Wind Project in NJ.)

The New Jersey Board of Public Utilities withdrew its fourth offshore wind solicitation in February, citing the Shell withdrawal and general uncertainty triggered by Trump’s executive order reflecting his well-known antipathy to offshore wind.

While Gov. Phil Murphy (D) said he supported the BPU’s decision, he still called offshore wind a “once-in-a-generation opportunity” to build a new industry and create jobs. “The offshore wind industry is currently facing significant challenges, and now is the time for patience and prudence,” he said.

March 17, 2025March 17, 2025

Overheard at CERAWeek 2025

Pattern CEO Armistead Says Transmission is Being Overlooked

HOUSTON — CERAWeek 2025 by S&P Global, held March 10 to 15, examined the changing energy landscape through 14 themes, from policy and regulation to climate and sustainability.

None seemed to draw more focus from the more than 10,000 attendees (a record) representing 89 countries than the rapid expansion of artificial intelligence technologies and their potential to transform the industry.

Almost four dozen presentations — some that conflicted with each other — included AI in their titles during the conference, including “democratizing AI” or “accelerating AI.” It was no surprise given the projected electricity demand of AI data centers and their potential for producing and managing and consuming power — as well as for helping energy systems become more efficient and sustainable.

Pattern Energy CEO Hunter Armistead | © RTO Insider

“Every time we come to CERA, you kind of think about themes that are going on in the conference,” Pattern Energy CEO Hunter Armistead said. “My next slide will be, of course, a mandatory slide talking about AI driving the flow of goods. I think everyone has to have that slide.”

Armistead was joking. But while AI may be reshaping the future of energy production, someone still must get the power from the source to where it’s needed.

“I’m a little surprised so far that when we talk about responding to [AI], there hasn’t been enough discussion about the critical role that transmission can play in delivering resiliency and actual capacity for this new load that’s coming,” he said. “We need to think bigger and faster, just like we talked about ‘all-of-the above,’ as far as energy resources that can deliver and meet this amazing challenge.”

Armistead’s company, which he co-founded, is in the business of building HVDC transmission lines to deliver those resources. Pattern has a development pipeline of over 25 GW of renewable energy and transmission projects, but Armistead is most proud of the company’s SunZia Wind and Transmission Project — a 550-mile, 525-kV line capable of moving 3.5 GW of renewable energy between New Mexico and Arizona.

“Spoiler alert: We’re crushing it. … It’s on-time and on-budget,” he said. “I’ve always said, when you’re building an $11 billion project, you better do it well because everyone’s watching.”

Construction began on SunZia in 2023. Armistead said it will begin commercial operations in 2026.

“For the last 20 years, we really had almost flat to no load growth. It’s been super hard to have a discussion with either rate-based entities or ISOs about the absolute need for increased transmission,” he said. “That’s all changing, and that’s super exciting. There’s actually now a catalyst that basically says we need to expand our grid and we need to expand our energy resources. And the part that I think the transmission provides for this is it allows efficient utilization.”

Pattern’s other U.S. HVDC project is the Southern Spirit Transmission, a 320-mile, 525-kV line able to transmit 3 GW of renewable energy to Mississippi and the Southeastern Regional Transmission Planning region. Pattern filed an application with FERC more than a decade ago and has cleared regulatory hurdles in Texas. Construction is targeted to begin in 2028, but Pattern must still negotiate with landowners and gain approval in Mississippi. (See ERCOT, PUC Adamant: Southern Spirit Doesn’t Interconnect Texas.)

Armistead said the developers have found a way around a Louisiana law that would have hindered the use of expropriation to secure private land for the line’s right of way.

“It’s embarrassing to say both these deals have taken 12 years to get to this point where they’re ready to go, but that’s where we are,” Armistead said. “The bigger challenge is getting the utilities of the Southeast to see why this helps them serve their customers that are coming in now. What we’re seeing is the huge load growth within the Southeast has the utilities and those customers saying, ‘Please, get Southern Spirit online.’ So, we see a lot of traction to actually deliver this.”

The Need for Speed

Armistead and Pattern have support in high places, including FERC Commissioner Judy Chang. Speaking on a panel discussing how to meet the power surge (The U.S. Energy Information Administration projects 4.6% demand growth in 2025, the highest in decades.), Chang said there is a need for speed.

FERC Commissioner Judy Chang | © RTO Insider

“From a regulator’s perspective, we want to move fast,” she said. “We encourage the utilities and any folks that can serve the new demand to move fast at the same time to protect existing customers, or all customers, and to make sure that we do this with an efficiency in mind and reliability in mind, and with a long-term view of where this whole industry, where the whole demand growth is going.”

“What do we need?” said fellow panelist Amanda Peterson Corio, Google’s head of data center energy, clean energy and power. “We need everything. … We need more grids. We have to find a way to be fast. Speed is the name of the game.”

Ever the optimist, Chang said the “unprecedented growth” in demand is creating an opportunity for the industry.

“It’s not an option to serve or not to serve this customer, whether it’s AI or manufacturing. We built a sector to serve customers,” she said.

Chang said she looks at the situation through “the lens of opportunities” around how the entire supply chain of the power industry — from generation to distribution — can serve these customers.

“From a regulator’s perspective, we have to make sure … we have secure energy and reliable energy and efficient use of energy. We want to make sure there’s equity and fairness in the way the cost of the network, the cost of the resources, are being paid for,” she said.

Christie: CC Gas Units the Key

Stressing the need for dispatchable resources to maintain grid reliability, FERC Chair Mark Christie relied on a statement that he’s made before: “We have a rendezvous with reality.”

FERC Chair Mark Christie | © RTO Insider

“We’re simply not ready to run a grid where we don’t have dispatchable resources,” Christie said. “That’s just the reality. We need to deal with it. We need to act accordingly.”

“I would say that’s not just a rendezvous with reality; it’s a rendezvous with a stark reality,” CERAWeek Chair Daniel Yergin said.

Christie bolstered his case by referring to PJM’s performance during the week of Jan. 20, when the RTO set a new winter peak at just over 145 GW. He ticked off the resources that made up the fuel mix at the pre-dawn peak: natural gas at 44%, and nuclear and coal at 22% each. (See PJM Sets Record Winter Peak Load.)

“What those numbers tell us is not that wind and solar don’t ever have an important role to play at different times, but when PJM, the largest grid operator in America, hit their winter peak, the resources that were keeping the lights on and the heat pumps running so people didn’t freeze were 88% dispatchable,” he said.

Christie acknowledged the lengthy time it can take to build combined cycle gas units but said they are vital sources of baseload power.

“The [PJM] combined cycle gas units were running like a top,” he said. “It doesn’t take long to get the combined cycle gas as your baseload generating resource of choice. It’s going to have to be, and if it takes seven years [to build], it takes seven years. It’s not an argument not to proceed with building combined cycle gas.”

After all, “I think it was Churchill who said, nothing concentrates the mind like being told you’re going to be shot at dawn,” Christie said. (He was actually paraphrasing Samuel Johnson: “When a man knows he is to be hanged in a fortnight, it concentrates his mind wonderfully.”)

Nuclear Hub in Texas?

Texas is taking quick action on its drive to become a “global nuclear energy hub,” as posited by a 2024 report.

Bills have been filed in the Texas Legislature that would set up a Texas Advanced Nuclear Energy Authority and create a $2 billion fund to offset construction costs, provide grants for reactors and fund research into nuclear power development. (See Texas Now Wants to be No. 1 in Nuclear Power.)

But even that may not be quick enough.

During a panel on the state’s Texas-sized ambitions, Dale Klein, former Nuclear Regulatory Commission chair and now a mechanical engineering professor at the University of Texas at Austin, said Gov. Greg Abbott has been proactive and recently hosted a reception for an industry group.

“When he heard it might be 2030 before new nuclear [could] be in Texas, he said, ‘That’s too late,’” Klein said. “He wants it earlier, but the federal government licenses reactors.”

Ischus Energy’s Jimmy Glotfelty (left) and former NRC Chair Dale Klein share a smile. | © RTO Insider

In the meantime, Texas A&M University has asked the NRC for an early site permit that would allow up to five 10- to 200-MW reactors to be built on its campus. The commission approved Abilene Christian University’s request in 2024 to build and test a 1-MW advanced nuclear reactor (ANR) that will be cooled by molten salt. Along the Gulf Coast, Dow Chemical and X-energy plan to develop four gas-cooled ANRs at a large chemical plant.

“We do everything big in Texas,” said former Texas Public Utility Commissioner Jimmy Glotfelty, who oversaw the report. “We don’t believe that the report is success. Success is steel in the ground, concrete in the ground, people working and building a plant. That is the end goal.”

Texas has two nuclear sites, Comanche Peak and the South Texas Project. Each generates about 2,500 MW of power and has room for two additional reactors.

“We want enough new nuclear megawatts in the state to help the economy continue to hum as it has been for a long time, but we also want to have a role in the production of all of the nuclear plants around the United States and around the world,” Glotfelty said.

“The momentum in the legislature is tremendous,” said Jeff Miller, vice president of business development at Bill Gates’ nuclear energy startup TerraPower. The company has partnered with the U.S. Department of Energy to build a reactor in Wyoming, using its sodium-cooled fast-reactor technology. “We are very bullish on Texas.”

Think Local Supply Chains

The U.S. Economic Policy Uncertainty Index may be one of the best measures of uncertainty for investors. With the Trump administration’s use of tariffs potentially starting a global trade war, the index has reached levels not seen since the COVID-19 pandemic and the global financial crisis in 2008.

Not to worry, said NextEra Energy CEO John Ketchum.

“We’ve been dealing with tariffs in our industry for a number of years. Tariffs are not a new thing for our industry,” Ketchum said, noting that the Biden administration kept some of the first Trump administration’s tariffs on solar panels. “Our supply chains have all adjusted to respond accordingly. But one thing that has changed is that our supply chains are largely American today.”

Ketchum said 90% of wind turbines being installed in the U.S. are made domestically, and the industry has been able to pivot to a nearly 100% domestic supply chain for batteries.

Canadian province Alberta set up Alberta House in the hotel lobby. | © RTO Insider

“When you turn this to solar, we’re buying more and more here in the U.S.,” he said. “We have been able to really diversify the supply chain. This is an industry that is an American industry. It’s a trillion-dollar American industry.”

“One thing which is important for us as big investors, since we build generation capacity on this side and the other side of the Atlantic, is the current geopolitically more tense environment,” said Markus Krebber, CEO of global renewables provider RWE. “It is very important to keep an eye on your supply chain, not only where the capacity is available, but also where it comes from, with risk around tariffs, trade wars and so on. Building a local supply chain is much easier and safer to build local than to rely on imports.”

“Anything that you import increases the amount of uncertainty that you have,” said GAF Energy President Martin DeBono, whose solar firm sells solar shingles.

Stacy Ettinger, a senior vice president with the Solar Energy Industries Association, said her organization has been working with its members to help them understand “what actually is happening.”

When it comes to tariffs, members are asking about the content of the measures, when they apply and what they apply to, so they can use the information when considering their own supply chain and procurement needs, Ettinger said.

March 17, 2025March 17, 2025

PJM Market Monitor Publishes Mixed Views in Annual Report

PJM’s markets provided reliable service in 2024, but tightening supply and demand are laying bare design flaws that have inhibited the competitiveness of the RTO’s markets, the Independent Market Monitor wrote in its 2024 State of the Market Report on March 13.

During a press briefing ahead of the publication of the report, Monitor Joe Bowring detailed several drivers behind the total price of wholesale power increasing 4.6% in 2024. Those include transmission service costs increasing from $10.7 billion in 2023 to $11.8 billion in 2024 and day-ahead energy costs going from $23.9 billion to $26.2 billion.

The real-time load-weighted average LMP was $33.74 in 2024, an 8.6% increase that Bowring largely attributed to PJM improperly applying the transmission constraint penalty factor (TCPF). He said that when lines are close to being overloaded, RTO staff will reduce their ratings by 5% in the security-constrained economic dispatch software, which leads to the TCPF being triggered more frequently and pushing prices to the $2,000/MWh cap. That practice, he said, accounted for $3.01 of the average LMP and 52.4% of the increase in 2024. Ancillary service redispatch costs contributed an additional 31.2%, and higher fuel and consumable costs accounted for 18.9%.

PJM spokesperson Jeff Shields said the RTO is reserving its comments on the report for its formal response. Wholesale consumer costs are also set to the discussed at the Public Interest and Environmental Organizations User Group meeting March 20.

The report found the energy market was overall competitive and effective, though increased ownership concentration in the local market led it to not be competitive, and the aggregate market was only partly so. In the more granular markets, the Monitor wrote that transmission constraints can create opportunities for market power. Market participant behavior was competitive, the Monitor wrote, with marginal units typically making offers close to their marginal costs — though some economic withholding was identified both under normal market conditions and at high demand.

The report said market sellers have been able to avoid being mitigated to their cost-based offers by submitting inflexible parameters or positive markups, an issue it said had LMPs. It also argued there are no mitigation protections in the aggregate market and that the application of market power rules in the local market need improvement. It recommended that PJM expeditiously implement its proposal to schedule any resources that fail the three-pivotal-supplier market power test on their cost-based offers. (See “Schedule Selection Formula Endorsed,” PJM MRC Briefs: July 24, 2024.)

Bowring noted another of the Monitor’s recommendations is being pursued by PJM in a joint package of proposals that would revise how uplift and deviation charges are assessed. It would prevent resources not following dispatch from receiving uplift payments and introduce a Tracking Ramp Limited Desired MW metric looking at how resources respond to instructions over time. (See “First Read on Proposal to Overhaul Uplift,” PJM MIC Briefs: March 5, 2025.)

Capacity Market

The Monitor’s outlook on the capacity market was dimmer. Overall, aggregate and local market structure was determined to be noncompetitive, as was participant behavior. The report faulted PJM’s rollout of marginal effective load-carrying capability for resource accreditation; resources categorically exempt from the requirement that market sellers offer into Base Residual Auctions withholding their capacity; gas generators being capped at their summer ratings; resources operating on reliability-must-run contracts not being required to offer into the market; and a maximum price set at the gross cost of new entry rather than 1.5 times net CONE.

The Monitor said the ELCC paradigm adds risk and volatility to the capacity market and recommended revising the model to use unit-specific data; match supply and demand in every hour of the year; and recognize actual unit performance and availability, rather than modeling performance simulated on data from a limited number of past performance assessment intervals. During the Critical Issue Fast Path process in 2023, the Monitor’s proposal to increase the granularity of the capacity market centered around evaluating resources’ ability to deliver capacity in every hour. Unit-specific accreditation remains a topic of discussion at the ELCC Senior Task Force. (See “Monitor Proposes Hourly Model with Annual Pricing,” PJM Stakeholders Finalize CIFP Proposals Ahead of Vote.)

While the Monitor lauded FERC’s Feb. 20 approval of a PJM proposal to eliminate the categorical must-offer exemption for intermittent and storage resources, it faulted an element of the package allowing market sellers to request a unit-specific offer cap set at a unit’s Capacity Performance quantifiable risk value without any net revenue offset. In comments on the filing, it argued that not accounting for energy and ancillary service revenues in the offer cap would undermine the purpose of the capacity market: to provide the missing money resources require to be available as capacity (ER25-785).

While supply and demand are tightening, Bowring said capacity prices in the 2025/26 BRA were double what would reflect a competitive offer under the market conditions. He attributed much of that to the exclusion of intermittent, storage and RMR resources from the supply stack, as well as the capping of gas generators at their summer ratings. Given that the majority of reliability risk is now concentrated in the winter, when gas units may perform better, he argued that as much as 20% of gas capacity is not recognized. (See PJM Market Monitor Releases Second Section of 2025/26 Capacity Auction Report.)

Bowring expressed support for an agreement PJM reached with Pennsylvania Gov. Josh Shapiro to set the maximum capacity clearing price at $325/MW-day, which would be roughly in line with the Monitor’s recommendation that the maximum price be defined as 1.5 times net CONE. The inclusion of a $175/MW-day price floor, however, could distort market outcomes, he said. (See PJM Presents Capacity Price Cap and Floor to Members Committee.)

Bowring said market signals cannot incentivize new generation without changes to PJM’s interconnection planning processes. He said the Monitor strongly supports the RTO’s Reliability Resource Initiative, which FERC approved to allow 50 projects ranked on their capacity contribution and in-service dates to be added the Transition Cycle 2 (TC2). The initiative’s goal of expediting resources that can quickly bring large amounts of capacity could be expanded by creating a permanent process that fast tracks new projects that would mitigate defined reliability needs. While Bowring said that could include general resource adequacy, it could also mitigate the need for transmission expansion and RMR agreements when generators retire. (See FERC Approves PJM’s One-time Fast-track Interconnection Process.)

The synchronized reserve market and its regional elements were determined to be noncompetitive because of ownership concentration in the Mid-Atlantic Dominion subzone. The market design was rated as flawed because of PJM unilaterally extending the operating reserve demand curve with a 30% adder in 2023. Deputy Monitor Catherine Tyler said the report includes new recommendations on reserves: Require that resources have automatic generator control (AGC) technology installed to be eligible to be synchronized and primary reserves, and eliminate the adder. During the March 6 Operating Committee meeting, PJM presented a plan to scale the adder back if reserve performance improves across three consecutive deployments, with the hope that changes to how it uses AGC during reserve deployments will improve performance. Tyler said that so long as not all reserve resources are required to have electronic communications installed, the impact of those changes will be muted. (See PJM OC Briefs: March 6, 2025.)

Bowring said that when the Monitor reached out to underperforming resources, it found that some were not getting the all-call phone call for as long as seven to eight minutes into a 10-minute deployment.

“The technology was outdated. … There’s been some improvements there, but not enough, and that requirement needs to be extended to everybody,” he said.

Bowring also argued that significant amounts of congestion revenue that is owed to consumers is being diverted through financial transmission rights auctions. If load held recognized property rights over congestion, some customers might be willing to sell variable congestion in return for a more predictable payment. But without the ability to set strike prices or receive all revenues from a sale, that capability does not currently exist. Total congestion in 2024 amounted to $1.75 billion, up 64.2% over the prior year, but 69.9% of that was paid to customers through auction revenue rights and the self-scheduled FTRs revenues offset.

“The goal of the FTR market design should be to ensure that customers have the rights to 100% of the congestion that customers pay. Customers have received $4.6 billion less in congestion revenues than load should have received, from the 2011/2012 planning period through the first seven months of the 2024/2025 planning period, as a result of flaws in the PJM FTR market design,” the Monitor said in the report’s announcement.

March 17, 2025

In Conversation with ISO-NE’s First Community Affairs Policy Adviser

As the Trump administration pulls federal support for environmental justice programs across the country, Ruben Flores-Marzan, ISO-NE’s first environmental and community affairs policy adviser, remains optimistic about the RTO’s efforts to engage with communities that historically have been absent from energy policy and planning discussions.

The RTO established the new position in response to a 2023 request from five of the six New England states for a position to help “provide an EJ and equity lens to ISO-NE’s management and staff; inform the development of ISO-NE initiatives, rules and operations; and engage EJ communities and stakeholders.” (See States Call for an Executive-level EJ Position at ISO-NE.)

The states wrote that the position should “serve as a critical bridge” between the RTO and the communities it serves, including the neighborhoods most affected by energy infrastructure. The request was supported by environmental advocacy groups, which have long called for a wider range of voices in ISO-NE’s decision-making processes.

ISO-NE hired Flores-Marzan, who has extensive professional experience as an urban planner, in July 2024. He has spent his first months on the job meeting with a wide range of community groups to listen to concerns; discuss ISO-NE’s role, abilities and limits; and take input on the RTO’s direction going forward.

“I’m talking to everyone, because the input of everyone is important to where we want to go,” Flores-Marzan told RTO Insider. “That’s a major part of what I’ve been doing: listening, reflecting, getting back in the engagement process with you to say, ‘Did I get that right?’”

He said his job is “essentially to reach out to different constituencies, learn from them, educate them about what the ISO does and does not do, and come up with different ways to continue engaging with them.”

Connecticut, Maine, Massachusetts, Rhode Island and Vermont have all passed laws intended to protect EJ communities. While the statutes and definitions vary, the laws generally aim to ensure that low-income communities, people of color and non-English speakers are provided equal opportunity to meaningfully participate in planning and policymaking processes.

EJ communities typically are located closer to energy infrastructure and face increased exposure to hazardous pollutants, including fine particulate matter and nitrogen oxides. A 2024 study by a coalition of advocacy groups found that about 80% of polluting generation facilities in Massachusetts are located within a mile of a state-designated EJ community. (See Report Shows Uneven Burdens of Power Infrastructure in Mass.)

Ruben Flores-Marzan, ISO-NE | ISO-NE

Low-income residents typically are also more vulnerable to the impacts of cost increases, although low-income discounts are available across all six New England states.

As an RTO, ISO-NE has significant constraints around what it can do to address EJ issues. It does not have jurisdiction over infrastructure siting and has indicated that it would need support from all six states to put a price on carbon or air pollution within its wholesale markets.

All six states also participate in the Regional Greenhouse Gas Initiative, which adds emissions compliance costs that ultimately affect prices within the markets.

Despite its constraints, the RTO is free to engage with the public on transmission planning, grid studies and market changes that could affect communities on the ground.

“What I can bring to the fold is that ability to embrace and incorporate people that haven’t been part of those discussions in the past,” Flores-Marzan said.

Flores-Marzan was born and raised in Puerto Rico and previously worked as a city planner in San Juan, working to procure wind and solar power to help the city decarbonize. In the mainland U.S., he has worked for the municipal governments of Providence, R.I.; Ware, Mass.; and East Windsor, Conn., where he helped site a 120-MW solar project.

He said his experience in Puerto Rico has helped him understand the importance of power system reliability, along with strong communication with the public about the issues that grid operators are facing.

“Energy drives everything; having that reliability is so important,” Flores-Marzan said.

Flores-Marzan is bilingual and said he hopes to boost the RTO’s outreach to Spanish speakers who face significant barriers to participating in ISO-NE’s public forums. While some state agencies across the region have implemented language access requirements for proceedings, ISO-NE public meetings are typically conducted only in English.

“A lot of Spanish speakers don’t know what the ISO is,” he said, adding that ISO-NE is translating some of its key documents into the language.

New England EJ advocates praised Flores-Marzan’s willingness to listen to community concerns and said the creation of the position is a step in the right direction for ISO-NE.

“I think the community affairs team has been working hard to listen to us and other community leaders … and to put in a best effort to answer our questions and understand our concerns,” said Mireille Bejjani, a community organizer who leads the Fix the Grid campaign. “I don’t think there was as much of that communication even just a few years ago.”

“We see this as a genuine commitment and a good first step,” said Susan Muller, senior energy analyst at the Union of Concerned Scientists. She said she is not aware of a comparable position that exists at any other RTO and expressed her hope that the role will serve as a model for other grid operators to follow. “They are rightly proud to be a leader.”

Moving forward, the advocates said they hope ISO-NE will increase its engagement with local communities, not just regionwide advocacy groups.

Bejjani said she hopes to see the “the buildout of a team at ISO-NE” focused on engaging EJ communities. At a higher level, Bejjani urged the RTO to open all the meetings of its Board of Directors to the public and put more resources into advertising its public meetings to increase participation.

“These are positive steps, but there’s more work to be done,” said Phelps Turner, a senior attorney at the Conservation Law Foundation. He added that it is “very important for the ISO to increasingly provide information that is more accessible that the everyday electricity consumer can understand and weigh in on.”

At the federal level, Trump administration has taken aim at EJ initiatives in its broader effort to remove support for diversity, equity, inclusion, and accessibility programs and protections. EPA Administrator Lee Zeldin has directed all regional EPA offices to eliminate their offices of environmental justice.

Eric Johnson, executive director of external affairs at ISO-NE, said he does not anticipate the change in federal policy affecting the new environmental and community affairs position or the RTO’s overall approach to community engagement.

“We created this position to be broader than environmental justice,” Johnson said, “and it’s really driven by the engagement we have with our states here in New England.

“The state’s priorities are not changing, and I don’t see our priority in that space changing. I think we’re just going to continue to build on this, and we’ll deal with whatever happens at the federal level.”

March 17, 2025

FERC Sides With SEEM Members After Rehearing

In a March 14 filing, FERC ruled that the Southeast Energy Exchange Market (SEEM) is compliant with the commission’s orders and reaffirmed its acceptance of the SEEM Agreement in 2021 (ER21-1111, et al.).

However, commissioners also ordered SEEM’s member utilities to update the market’s manual to account for changing a key requirement and submit a compliance filing within 30 days confirming they have done so.

FERC’s filing came after the commission requested briefings in June 2024 from SEEM’s members and its opponents, in response to a 2023 order from the D.C. Circuit Court of Appeals remanding FERC’s approval of the market. (See FERC Requests Briefings on SEEM After DC Circuit Order.) The commission wanted to hear arguments on:

- Whether SEEM is a loose power pool.

- If so, whether and how SEEM “is consistent with or superior to the open-access requirements for loose power pools” in Order 888.

- If SEEM is not a loose power pool, whether and how it is superior to or consistent with the pro forma open access transmission tariff.

- Whether the market’s non-firm energy exchange transmission service (NFEETS) should be considered a non-pancaked rate.

- Whether NFEETS is “comparable to traditional transmission arrangements in bilateral markets.”

- Whether entities with a source or sink outside of SEEM’s territory could conform with the technical requirements of the market’s matching platform.

Southern Co., Dominion Energy, Duke Energy and Louisville Gas & Electric, all members of SEEM, answered the commission’s request in an August 2024 briefing that argued the market is not a loose power pool because NFEETS is not a discount or a special rate, as FERC previously determined. They further claimed that NFEETS is pancaked and that owning a source or sink connected to a SEEM transmission provider is necessary for SEEM to be technically feasible.

SEEM’s opponents, a group of environmental organizations and renewable energy trade organizations, countered the following month with a filing arguing that the market’s supporters focused on technical issues while ignoring the fact that SEEM “has walked and quacked like an exclusive power pool” since its conception. The opponents said SEEM violated Order 888 by systematically excluding independent power producers, while energy sales have been dominated by just a few utilities. (See SEEM Opponents Push Back on Supporters’ Claims.)

In its March 14 filing, FERC agreed with SEEM’s members that the market is not a loose power pool. Commissioners said that, based on information provided in the reply comments, NFEETS “cannot neatly be described as either pancaked or non-pancaked,” but that the service “is best characterized as a pancaked rate because each SEEM transaction relies on the acquisition of NFEETS from each participating transmission provider.”

The commission added that even if NFEETS did not disqualify SEEM as a loose power pool, the market still would comply with Order 888. FERC said though the order “prohibits participation requirements that are exclusionary based on geographic location or entity type, the commission does not read [Order 888] as prohibiting reasonable technical requirements for participation.”

These “reasonable technical requirements” include the source/sink requirement, FERC said, because it ensures that participants are close enough for NFEETS to function properly.

“These are not optional characteristics that constitute artificial barriers to participation,” FERC said. “Rather, they are technically integral to the goal of SEEM — to efficiently match buyers and sellers of energy with transmission capability that is unused through any existing transmission services.”

FERC did note SEEM members’ statement that they have amended the market’s business practices manual to allow utilities to use pseudo-ties to satisfy the source/sink requirement. Pseudo-ties are used to represent interconnections between two balancing authorities where no physical connection exists between the load or generation and the power system network.

The commission said the pseudo-tie option “significantly affects rates and services because it is the only option for such resources to participate in SEEM and use NFEETS.” FERC said the terms of service for using pseudo-ties, and the process for evaluating such mechanisms, therefore must be included in the SEEM Agreement, and gave members 30 days to submit a compliance filing verifying the agreement has been updated with the option.

March 17, 2025March 17, 2025

NM Regulators Poke Assumptions Behind EPE’s Markets+ Choice

A recent study that contributed to El Paso Electric’s decision to join SPP’s Markets+ rather than CAISO’s Extended Day-Ahead Market (EDAM) has raised questions among New Mexico regulators.

The results of the Brattle Group analysis were presented to the New Mexico Public Regulation Commission (PRC) during a March 13 workshop.

The workshop followed El Paso Electric’s announcement Jan. 24 that it would join Markets+. The announcement surprised commissioners, who were expecting to see results of additional studies before EPE selected a market. (See EPE’s Markets+ Decision ‘Not Transparent,’ NM Regulators Say.)

In the new analysis, Brattle updated results from an earlier study for Public Service Company of New Mexico (PNM) and EPE with a “sensitivity case” that includes the value of the Eddy County tie. The tie is a 345-kV transmission line that links EPE with Southwestern Public Service Co., which is a member of the SPP RTO in the Eastern Interconnection.

Under that case, EPE’s annual benefits would be $19.3 million if both New Mexico utilities join EDAM, $20.1 million if they join Markets+ and $18.8 million if EPE goes with Markets+ while PNM joins EDAM, Brattle projected in the new analysis.

That contrasts with results from Brattle’s previous study, which projected EPE’s benefits would be $19.1 million a year if both utilities joined EDAM versus $9.1 million if both joined Markets+. The benefits are in comparison to a “current trends” (CT) case in which PNM and EPE remain in CAISO’s Western Energy Imbalance Market (WEIM) and don’t join a day-ahead market.

PNM announced its choice of EDAM in November. (See PNM Picks CAISO’s EDAM.)

Eddy Optimization

In its new analysis, Brattle “optimized” the Eddy County tie to SPP East for scenarios where EPE joins Markets+, assuming that trade flows freely across the tie. The model assumes the SPP East market is liquid enough to supply or receive all Eddy tie flows at prices comparable to those of Markets+.

“Whenever El Paso is purchasing power, we assume that the tie’s importing; whenever they’re selling power, we assume that they’re exporting,” Brattle Group principal John Tsoukalis said during the workshop.

In the cases where EPE is in EDAM or only in WEIM, the Eddy tie isn’t optimized; instead, its value is assumed to be the same as it was in 2023.

The optimization is only in the Markets+ cases because Markets+ and SPP East have the same market operator, said Tsoukalis, who said his understanding is that SPP is planning for the optimization. While Tsoukalis said it’s possible that SPP would optimize flows with EDAM, he said he’s not aware of any discussions to do so.

Commission Chair Pat O’Connell questioned the assumption, saying it implies something “kind of remarkable.”

“You have to accept that SPP would not work to optimize interregional transfer unless you’re in Markets+,” O’Connell said.

Commissioner Gabriel Aguilera also wondered whether there would be an opportunity for Eddy County tie optimization through a seams agreement in a case where EPE joins EDAM. Aguilera asked if Brattle could calculate benefits in two additional ways: one in which the Eddy tie is not optimized in any of the four scenarios, and another in which it is optimized in all four scenarios, including cases where EPE joins EDAM or remains solely in WEIM.

“It seems like all of those have an equal possibility of occurring,” Aguilera said.

EPE representatives agreed to bring those variations of the analysis to the commission.

El Paso Electric and PNM are co-owners of the 200 MW Eddie County tie: EPE has rights to two-thirds of the capacity, and PNM has rights to the remaining third. That prompted questions from the commission on why the Brattle analysis optimized the tie’s entire 200 MW in the two cases where EPE joins Markets+.

“PNM owns part of this, and yet your sensitivity analysis relies so heavily on using 200 MW,” Aguilera said.

Weighing the Choices

After the latest Brattle analysis found similar monetary benefits in the different scenarios, EPE turned to additional factors in making its day-ahead market decision.

SPP’s experience as an RTO operator and its record of expanding renewable energy resources make “it a trusted partner in this endeavor,” EPE said in its announcement. (See El Paso Electric to Join SPP’s Markets+ in 2028.)

During the PRC workshop, EPE representatives said another advantage of Markets+ relates to resource adequacy. Markets+ will require all participants to join Western Power Pool’s Western Resource Adequacy Program (WRAP).

“It is important to make sure that everybody is on equal footing on how you’re calculating your resources,” said Emmanuel Villalobos, EPE’s director for market development and resource strategy.

Instead of facing a WRAP requirement, EDAM participants will undergo a daily resource sufficiency evaluation (RSE). EDAM participants have the option to join WRAP, but it’s not required.

Aguilera questioned EPE’s ability to meet WRAP’s requirements. He said the utility might need to accelerate resource procurement, with a resulting cost impact to customers.

“As a regulator who is concerned about affordability, I would see that as a benefit in EDAM to have more of that flexibility” on resource adequacy, Aguilera said. “Especially given that WRAP hasn’t taken off. It’s been delayed. It’s been having its own issues.” (See WRAP Members Align on Key Issues to Prioritize.)

EPE did not participate in Phase 1 of Markets+ development and has not yet signed a Phase 2 funding agreement with SPP — a move Villalobos said EPE is likely to make in the first quarter of 2026. The funding commitment would be in the form of collateral rather than money given upfront, he added.

Consultant Utilicast is wrapping up a gap analysis for EPE, looking at steps the utility needs to take before joining Markets+.

EPE expects to begin Markets+ implementation activities next year and start participating in the market in 2028.

March 17, 2025March 17, 2025

NJ Releases Electrification-focused Energy Master Plan

Facing an expected surge in energy demand, New Jersey’s Board of Public Utilities outlined a draft Energy Master Plan (EMP) on March 13 that would continue the state’s existing, vigorous electrification strategy while also accepting “emerging clean firm technologies,” such as nuclear power.

The 2024 EMP, which the BPU began researching last year, succeeds the 2019 version, which formed the cornerstone of Gov. Phil Murphy’s aggressive renewable energy strategy. It included the aggressive promotion of offshore wind and solar generation, electric vehicle adoption with incentives, and building electrification.

The new plan predicts a 66% increase in electricity demand by 2050 if the state pursues its existing policies, driven by the power needs of new data centers, building electrification and the shift from fossil fuel-powered vehicles to EVs.

What impact the latest master plan will have is unclear, however. Murphy is serving his last year in office, and the vigorous opposition to renewable energy in the current White House may limit some of the state’s efforts.

The draft plan contains few concrete policy decisions pending further stakeholder input. It concludes that the state’s clean energy goals can be achieved through a “rapid and sustained pace of low-carbon technology deployment.”

Eric Miller, executive director of the governor’s Office of Climate Action and the Green Economy, said the draft plan offers an “actionable and flexible approach to achieving our clean energy future that’s grounded in the best data available.”

Among the findings is that the state should adopt a short-term and vigorous pursuit of “no regret” climate actions, such as building and transport electrification, utility-scale solar, and battery storage deployment, the BPU said in its presentation.

Miller said a “no regrets” policy is one that “we know provides significant benefits to the climate and the state’s ratepayers without material downsides.” Such policies are central to all of the three future energy path scenarios outlined in the plan, he said.

Mitigation Strategies

The EMP is part of the state’s effort to reach 100% clean electricity by 2035 and an 80% reduction in gas emissions by 2050.

It was compiled by Energy + Environmental Economics (E3) through research, modeling and stakeholder input from four public hearings in spring 2024. (See NJ Master Plan Speakers Seek Sweeping Electrification Plan.)

E3 looked at four “Climate Pathways Scenarios” with varying levels of emission reductions, including current policy, which it said would not meet the state’s goals.

- current policy: 50% renewable portfolio standard; 5 GW of offshore wind would be developed; slow adoption of heat pumps; 25% cut in building gas use by 2050; and EV adoption driven by Advanced Clean Cars and Advanced Clean Trucks programs.

- high electrification: 100% clean energy standard by 2035; rapid heat pump adoption; 80% cut in building gas use by 2050; 94% of vehicles are EVs by 2050; and industrial gas use is reduced by 50% by 2050.

- demand management: 100% clean energy standard by 2035; 60% of existing homes and commercial buildings have “envelop upgrades,” or exterior wall insulation installed; 5 GW of new solar added by 2050; widespread managed EV charging to reduce peak load; and reduction in vehicle miles traveled through urban design and public transit.

- hybrid electrification: 100% clean energy standard by 2035; 40% of homes have a heat pump and a backup gas system; 94% of vehicles are EVs, but 20% are plug-in hybrids; and advanced renewable fuels are blended with fossil gas and petroleum to mitigate a portion of non-electrified fuel use.

A spokesperson from Murphy’s office said all three of the mitigation scenarios enable the state to reach its goals. The final report will contain “a preferred scenario, but it will not be presented as the only scenario for the future,” they said.

E3 said the high electrification scenario has the greatest impact on the grid, while the other two are designed to mitigate the stress on the grid using peak demand reduction. Electricity demand is expected to grow by more than 90% by 2050 in all three scenarios, with the biggest increase — 109% — experienced under high electrification.

Meeting demand would require growth in nuclear power, according to E3’s presentation. There also would be a “role” for “emerging clean firm technologies” such as long-duration storage, and generators fueled by hydrogen or renewable natural gas, it said.

The mitigation strategies also would rely heavily on rebates to make the new clean technology accessible, the BPU said. That would be especially so in the adoption of heat pumps, which cost about $20,000 to install, compared to $5,000 for a fossil-fuel boiler, the agency said.

But by 2035, the average energy bill for electrified households and those powered by fossil fuels will be “comparable,” E3 said. For example, the average monthly energy bill, including vehicle fuel, would range from $325 to $360 in 2025, depending on whether the household was all electric or uses some gas. And by 2035, the range would be from $385 to $419, the BPU said.

Support and Opposition

The BPU presented the plan during a three-hour online public hearing that drew varying reactions from 40 speakers.

Patty Cronheim, a clean energy advocacy consultant, said she fully supported the high electrification scenario, in part because she has renovated her 100-year-old home to be a “complete electrification building.”

“I understand firsthand how building electrification can help with the decarbonization transition by relieving peak summer demand,” she said. She urged the BPU to make sure that data centers are “on the hook for clean electricity generation that benefits the public and not be a strain on a system that costs New Jerseyans.”

David Pringle, a steering committee member of environmental group Empower NJ, said his “main testimony today is going to be skepticism.”

He said the Murphy administration “hasn’t come close” to implementing all the air emissions and “adaption rules” laid out in the 2019 EMP, and even if it implemented the 2024 rules, the next administration could have its own plans.

While BPU and E3 officials stressed that affordability and the cost to ratepayers is a key element in the state deciding its energy strategy, Andrew Kuntz, staff attorney with the New Jersey Division of Rate Counsel, expressed concern that there was little evidence so far to support that claim.

“The current version of the 2024 EMP is devoid of any mention of a rate impact study,” he said. “Affordability matters, and it must be part of this process.”

Ray Cantor, a lobbyist for the New Jersey Business & Industry Association, said the plan has “a wrong starting point” in focusing on electrification.

“We need to rely on what we know works, and primarily at this point in time, we need more natural gas generation,” he said.

March 16, 2025March 17, 2025

FERC to Rule on SPP’s RA Requirement for Winter

FERC is expected to rule on SPP’s proposed tariff revisions adding a winter season resource adequacy requirement (RAR) during its monthly open meeting March 20 (ER24-2397).

The commission in November 2023 rejected the proposed revisions, finding SPP’s proposal did not contain any requirement that the resources included in load-responsible entities’ workbooks are expected to be available. FERC also said the grid operator had not demonstrated it is reasonable to permit LREs to rely on resources that are not expected to be available to satisfy their winter season RARs.

SPP filed a response June 28, asking for an effective date of Jan. 1, 2025.

The RTO’s Board of Directors approved the winter season obligation in August 2023. (See “Board, RSC Endorse Winter Obligation,” SPP Board/Members Committee Briefs: July 24-25, 2023.)

In February, the board approved a 38% planning reserve margin for the 2029 winter season. The 2029 summer season has a 17% PRM.

The commission also has placed on its agenda an order that may be related to requests for rehearing by MISO and Montana-Dakota Utilities of a 2024 order that denied their complaints over a North Dakota cryptomining facility’s burdening a jointly owned flowgate with SPP (EL24-61).

MISO and MDU sought to have market-to-market coordination on the line lifted after the Atlas Power Data Center added a 200-MW load to an SPP load pocket in northwestern North Dakota. They maintain that congestion management should not extend beyond SPP’s responsibility. (See MISO Argues to FERC for 2nd Look at Crypto-stressed Flowgate Management.)

MISO in January filed a review petition with the D.C. Circuit Court of Appeals (25-1011) after FERC denied rehearing requests in November 2024, saying they “will be addressed in a future order.” MISO says the “future order” has not yet been issued in any of the underlying proceedings.

FERC’s agenda also includes:

- A response to SPP’s compliance filing in its effort to facilitate RTO membership for nine Western Interconnection entities. The commission found the grid operator’s tariff for its Western RTO to be deficient in October 2024 (ER24-2185). (See FERC Issues Deficiency Letter for SPP’s RTO West Tariff.) FERC asked for further clarifications on six issues, including transitioning the expansion members’ transmission service request queues into SPP’s existing transmission service study processes and how LMPs on both sides of the West DC ties will inform how the RTO optimizes the interties’ use. SPP is trying to be the first grid operator with markets in both the Western and Eastern Interconnections. RTO West is scheduled to go live in April 2026.

- An order related to SPP’s request to incorporate a mark-to-auction collateral requirement for its transmission congestion rights markets. The RTO asked for an effective date of May 1 to allow for enough time to add the collateral requirement before the TCR annual auction (ER24-2906).

March 16, 2025March 17, 2025

Experts Urge Texas Policymakers to Go Big with 765-kV Transmission

ERCOT already operates a power system as large as those in several European countries, but demand growth is expected to bring it up to the level of PJM and MISO, which has the industry considering building a new system of 765-kV lines to transmit power around Texas.

“When you think about PJM’s high-voltage overlay, they have this huge 765- and 500-kV system to move power back and forth and back and forth,” Grid United President Kris Zadlo said on a webinar March 13 hosted by Americans for a Clean Energy Grid. “And I think that’s kind of what we need to start thinking about if we’re going to be going to such a large system.”

In the next decade, peak demand could double on ERCOT’s grid while overall consumption of power triples, said Michael Webber, professor of mechanical engineering at the University of Texas at Austin.

The new demand is being driven by different factors. Data centers are part of the picture, but other sources include the need to electrify more of the oil and gas production in the booming Permian Basin and keep up with the general population and economic growth in Texas. ERCOT has grown 1 to 2% per year recently, when much of the rest of the country grew little to none. Growth rates now are up to 3 to 4% annually, Webber said.

CenterPoint Energy forecasts demand in and around Houston will grow by 10 GW, which is the equivalent of adding Belgium’s total power demand to the system.

“So, we have to add a Belgium to Houston, but we also have to add a Belgium to West Texas, and maybe half of Belgium to Abilene for data centers, or whatever,” Webber said. “If you start to add it up, and maybe a 10th of a Belgium here and there for LNG export terminals, which all say they’ll be electrified … it’s a lot of demand.”

If all the demand were in one part of Texas, it could be met by building one power plant, but given how spread out it is across the state, transmission needs to be part of the picture, Webber said.

“All of this adds up to this new estimate of 150 GW of load coming down the pipe,” said Conservative Texans for Energy Innovation’s Michael Jewell. “When the legislature heard about that, I think it really kind of freaked them out and got them to say, ‘You know, maybe there really is something that needs to happen.’ And I think it really has changed the dynamic to, ‘We do need to think about, how are we going to address this?’”

Building transmission is part of the answer, but policymakers could decide to stick to 345-kV lines, as they did when Texas last did a major buildout of transmission more than 15 years ago with the Competitive Renewable Energy Zone lines to bring wind to customers.

“One of the early questions was, should we be looking at 500-kV lines?” Jewell said. “And that kind of fell to the wayside as the advantages of 765 and the greater ability to move power there kind of outweighed almost what one could think of as an interim step in that regard.”

The idea of building out 765-kV lines first was broached in the legislature with the aim of helping Permian Basin drillers continue to electrify. Once the focus was widened to the entire state, 765 kV made more sense, he added.

While 765 kV is the largest voltage used in the U.S., China has built an overlay system with 1,100-kV lines, Webber said. Voltages that high start to come up against manufacturing issues, Zadlo said.

“Once you go above 345, whether it’s 500 or 765, it’s the same thing,” Zadlo said. “My understanding is the 765 breakers come out of the same factories that are making 345 breakers. So really, there’s no difference there. I think the only big difference is when it comes to transformer production.”

Building a series of 765-kV lines also takes about the same amount of time as building 345, he added.

Forecasting demand growth always comes with uncertainty, but given that some of the new loads can come online in a year while power plants take three or four, and transmission in Texas takes at least six, it makes sense to start planning for it now, Zadlo said.

“You can’t accelerate a transmission line, right? You just can’t,” Zadlo said. “It’ll be disastrous if we’re wrong; if we don’t build that line on time. … But you can always slow it down if the load doesn’t materialize. You can always pull back the plans.”

Another reason to move with big infrastructure buildouts is they almost always are used to their capacity, Webber said. Railroads, broadband, the highways and other historical examples all involved some overbuilding, with only massive technological changes like the advent of automobiles and highways making the railroads less useful a century later.

“If you’re going to go to the trouble [of building] capacity, you might as well build more capacity, and the higher voltage gives you more capacity,” Webber said. “So, I’d argue that this is actually the American way of doing things, and it would just give us more ability to move things around.”

March 16, 2025March 17, 2025

MISO Members Grapple with 54 GW in Incomplete Gen, Predict Storage Expansion

NEW ORLEANS — MISO members haven’t landed on easy answers in getting the approximately 54 GW of unfinished generation that has cleared the interconnection queue online sooner.

MISO’s Advisory Committee convened March 12 during Board Week to focus on the footprint’s lagging generation projects and how future delays could be prevented. (See MISO Members to Explore Ways to Rev Up Stalled Generation Builds.)

Despite the focus on commercial operation delays, members agreed later in the meeting that energy storage eventually will flourish in the footprint.

Illinois Commerce Commissioner Michael Carrigan said some increased transparency from MISO about the challenges in getting generation online would be helpful. He said he appreciated the RTO’s new reporting on the status of approved projects’ commercial operation dates but said more detail on the delays would be valuable for stakeholders.

Wisconsin Public Service Commissioner Marcus Hawkins said he has observed delayed projects inch past their original budgets into cost overruns. “So, ratepayers are affected by these delays.”

Multiple stakeholders also said the delays are set to affect states’ resource plans.

Clean Grid Alliance’s Beth Soholt said states and load-serving entities might consider speeding up their procurement timelines or consider changing their permitting processes. She said that she, like many, “underappreciated” how decisively the COVID-19 pandemic upended the generation development cycle. Soholt said some developers struggled with virtual meetings while land agreements languished without construction. “There’s still a hangover there.”

Soholt also noted MISO has introduced several rule changes in its interconnection queue over the last few years, which may have some developers scrambling.

“Interconnection customers have been living by the rules that MISO has set,” she said.

Hawkins suggested the full effect of the RTO’s latest rule changes — the stepped-up fees, automatic withdrawal penalties, more rigorous proof of land rights and annual megawatt cap — have yet to settle in. Hawkins said he thinks projects that are processed in the stricter environment will arrive better vetted. However, he said, stakeholders might have to accept that the energy transition may be interspersed with failed plans for generation projects.

“I think this just might be some of the new normal … this presence of stalled or delayed resources,” Hawkins said.

Soholt said that while a lot of the responsibility for delayed projects is “rightly” on interconnection customers, she asked for a dialogue with transmission owners on what can be done about their own staff shortages and supply chain woes that grind network upgrades to a halt.

“All it says is, ‘TO Delay.’ So, can we get more granular?” Soholt asked of TOs’ reports to FERC. She also requested that more light be shed on how TOs prioritize construction of network upgrades. She said interconnection customers don’t know enough about what causes network upgrade bottlenecks.

Pelican Power’s Tia Elliott suggested that stakeholders and MISO create a method to match existing projects in the queue to a nearby LSE’s forecasted needs.

The Union of Concerned Scientists’ Sam Gomberg asked if it was worth examining the RTO’s generator interconnection agreement contracts to see if there are any impediments or out-of-date language.

Alliant Energy’s Mitchell Myhre said MISO’s proposed resource addition lane for its queue should help get projects online faster. (See MISO Says Queue Fast Track Design Settled, Ready for FERC.) The RTO is set to file that proposal imminently.

But Gomberg said he did not see how an express lane in the queue would keep those projects from running into the same “buzz saws” of delays that plague projects in the traditional queue.

Soholt said MISO should have been focused on its existing queue all along instead of introducing “chaos” with a fast lane, in which projects will need transmission capacity alongside the projects in the regular queue.

At a meeting of the MISO Board of Directors’ System Planning Committee on March 11, Aubrey Johnson, the RTO’s vice president of system planning and competitive transmission, said members recently have been picking up the pace on generation additions despite the delays. He said members managed to add a record 7.5 GW in nameplate capacity in 2024, up from 5.6 GW in 2023 and 3.5 GW in 2022. In the first half of 2025, the RTO expects to have 5 GW in new nameplate capacity. Members have added 1.4 GW in nameplate capacity since the beginning of the year.

The interconnection queue contains 308 GW across 1,695 projects; 145 GW of that is solar generation.

Johnson also said he hopes the recently approved megawatt cap on annual entrants in the queue ends the “mad rush” of projects in recent years and leads to more thoughtful development.

Storage in the Wings

Later in the Advisory Committee meeting, members agreed that while storage might be a slow burn now, it will heat up in the 2030s.

MISO should contemplate new rules now, they agreed.

The RTO has just 164 MW of operational storage in its market, with about 2.7 GW approved and waiting to come online. Its interconnection queue contains 61 GW of nameplate capacity across 388 storage project proposals.

Executive Director of Markets Innovation and Strategy Zak Joundi said that although storage is in its “infancy” and growing modestly in the footprint, the RTO expects 12 GW of storage around 2030 to become 53 GW by 2043.

Gomberg predicted a rapid deployment of storage in the coming years and said MISO needs to hammer out appropriate market rules to compensate the “versatile” resources that can supply capacity, as well as relieve transmission constraints.

Myhre said he anticipates the jump in storage will mimic the rise in wind capacity that began about two decades ago. He said megawatts will quickly multiply into gigawatts, with the RTO and stakeholders “learning together” to draw up participation rules.

Jim Dauphinais, representing a collection of MISO end-use customers, said that while battery storage will prove important, the current technology is limited to about four hours of output.

“It doesn’t give us the same thing as a generation with a sustained supply of fuel. … While it can plug the gap, it can’t solve the exit of large generation resources,” he said.

Dauphinais also said storage technologies are only going to be pursued to the extent that they earn revenues. He urged the RTO to begin forming market signals.

NextEra Energy’s Erin Murphy said storage developers right now may be hesitant to build in MISO because of the investment uncertainty over their accreditation values.

Joundi acknowledged the RTO has work to do on modeling how storage would contribute to the grid. But he also said current storage volumes are low.

Murphy pressed MISO to begin modeling work even with a small sample size.

“We have to say, ‘We’re going to put a stake in the ground and begin,’” Murphy said.